Stifel · PROSPECTUS 13,333,334 Shares Matador Resources Company Common Stock Matador Resources Company is offering 11,666,667 shares of its common stock, and the selling shareholders

PROSPECTUS

13,333,334 Shares

Matador Resources CompanyCommon Stock

Matador Resources Company is offering 11,666,667 shares of its common stock, and the sellingshareholders are offering 1,666,667 shares of our common stock. This is our initial public offering, and nopublic market currently exists for our shares. We will not receive any of the proceeds from the sale of sharesby the selling shareholders.

Our common stock has been approved for listing on the New York Stock Exchange under the symbol“MTDR.”

Investing in our common stock involves risks. See “Risk Factors” beginning on page 23.

PRICE $12.00 PER SHARE

Price to Public

UnderwritingDiscounts andCommissions(1)

Proceeds toCompany

Proceeds toSelling Shareholders(1)

Per Share $ 12.00 $ 0.81 $ 11.19 $ 11.19Total $160,000,008 $10,602,798 $130,550,004 $18,847,206

(1) Certain selling shareholders that are selling 243,460 shares in this offering will not berequired to pay underwriting discounts or commissions. See “Underwriters” foradditional information.

We have granted the underwriters the right to purchase up to an additional 700,000 shares of common stockto cover over-allotments. The selling shareholders have granted the underwriters the right to purchase up to1,300,000 additional shares to cover over-allotments.

The Securities and Exchange Commission and state securities regulators have not approved or disapprovedof these securities, or determined if this prospectus is truthful or complete. Any representation to thecontrary is a criminal offense.

The underwriters expect to deliver the shares of common stock to purchasers on February 7, 2012.

RBC CAPITAL MARKETS CITIGROUPJEFFERIES

HOWARD WEIL INCORPORATED STIFEL NICOLAUS WEISEL

SIMMONS & COMPANY INTERNATIONAL STEPHENS INC. COMERICA SECURITIES

February 1, 2012

Karnes

Eddy

Lea

Atascosa

Dimmit

Gonzales

Harrison

Upshur

Van Zandt

Orange

La Salle

Webb

Wilson

Winkler

Bienville

LincolnBossier

Caddo

dver

Zavala

Chaves

KarnesAtascosa

Dimmit

Gonzales

Harrisisono

Upshur

Van Zandt

OOrange

La Salle

Webbb

Wilson

Winkleerr

Zavala

Bienville

LincolnBossiesier

Caddoo

dver

Eddy

Lea

Chaves

Rich

Lincoln

BearLake

Idaho

Utah

Wyoming

Wyoming, Utah, Idaho

144,368 gross acres / 135,862 net acres (2)

MATADOR HEADQUARTERS

DALLAS, TEXAS

Northwest Louisiana

and East Texas

Production – 39.1 MMcfe/d (1)

Proved Reserves – 152.7 Bcfe (2)


South Texas




Southeast New Mexico

and West Texas




Matador Resources

Company Totals



236,263 gross acres / 197,764 net acres (2) AREAS OF ACTIVITY

(1) For the nine months ended September 30, 2011.(2) At September 30, 2011.

TABLE OF CONTENTS

Prospectus Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Cautionary Note Regarding Forward-Looking Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48Use of Proceeds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50Dividend Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52Capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53Dilution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54Selected Historical Consolidated and Other Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . 57Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130Compensation of Named Executive Officers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 143Certain Relationships and Related Party Transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 167Corporate Reorganization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 171Principal and Selling Shareholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173Description of Capital Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 179Shares Eligible for Future Sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 183Material U.S. Federal Income and Estate Tax Considerations to Non-U.S. Holders . . . . . . . . . . . . . . . . . . . . 185Underwriters (Conflicts of Interest) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 189Legal Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 198Experts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 198Where You Can Find More Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 198Index to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-1Glossary of Oil and Natural Gas Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

You should rely only on the information contained in this prospectus and any free writing prospectusprepared by or on behalf of us or to which we have referred you. Neither we nor the selling shareholdershave authorized anyone to provide you with information different from that contained in this prospectus andany free writing prospectus. We and the selling shareholders are offering to sell shares of common stock,and seeking offers to buy shares of common stock, only in jurisdictions where offers and sales arepermitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless ofthe time of delivery of this prospectus or any sale of the common stock.

Until February 26, 2012, all dealers that buy, sell or trade our common stock, whether or notparticipating in this offering, may be required to deliver a prospectus. This requirement is in addition to thedealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsoldallotments or subscriptions.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based onindependent industry publications, government publications or other published independent sources.Although we believe these third party sources are reliable and that the information is accurate and complete,we have not independently verified the information. Some data is also based on our good faith estimates.

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PROSPECTUS SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. Youshould read the entire prospectus carefully before making an investment decision, including the informationpresented under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements”and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and thehistorical consolidated financial statements and related notes thereto included elsewhere in this prospectus.Unless otherwise indicated, information presented in this prospectus assumes that the underwriters’ optionto purchase additional common shares is not exercised. We have provided definitions for certain oil andnatural gas terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms” beginning onpage A-1 of this prospectus.

In this prospectus, unless the context otherwise requires, the terms “we,” “us,” “our,” and the“company” refer to Matador Resources Company and its subsidiaries before the completion of ourcorporate reorganization on August 9, 2011 and Matador Holdco, Inc. and its subsidiaries after thecompletion of our corporate reorganization on August 9, 2011. Prior to August 9, 2011, Matador Holdco,Inc. was a wholly owned subsidiary of Matador Resources Company, now known as MRC EnergyCompany. Pursuant to the terms of our corporate reorganization, former Matador Resources Companybecame a wholly owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRCEnergy Company, and Matador Holdco, Inc. changed its corporate name to Matador Resources Company.See “Organizational Structure” on page 14 and “Corporate Reorganization” on page 171 of thisprospectus.

In this prospectus, unless the context otherwise requires, the term “common stock” refers to shares ofour common stock after the conversion of our Class B common stock into Class A common stock upon theconsummation of this offering, as the Class A common stock will be the only class of common stockauthorized after this offering, and the term “Class A common stock” refers to shares of our Class Acommon stock prior to the automatic conversion of our Class B common stock into Class A common stockupon the consummation of this offering. See “Description of Capital Stock.” In addition, in this prospectus,we have assumed that 285,000 shares of common stock will be issued to certain holders of stock optionsprior to consummation of this offering and 243,460 of these shares will be sold by the option holders asselling shareholders in this offering.

Matador Resources Company

Overview

Matador Resources Company is an independent energy company engaged in the exploration,development, production and acquisition of oil and natural gas resources in the United States, with aparticular emphasis on oil and natural gas shale plays and other unconventional resource plays. Our currentoperations are located primarily in the Eagle Ford shale play in south Texas and the Haynesville shale playin northwest Louisiana and east Texas. These plays are a key part of our growth strategy, and we believethey currently represent two of the most active and economically viable unconventional resource plays inNorth America. We expect the majority of our near-term capital expenditures will focus on increasing ourproduction and reserves from the Eagle Ford and Haynesville shale plays as we seek to capitalize on therelative economics of each play. In addition to these primary operating areas, we have acreage positions in

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southeast New Mexico and west Texas and in southwest Wyoming and adjacent areas in Utah and Idahowhere we continue to identify new oil and natural gas prospects.

We were founded in July 2003 by Joseph Wm. Foran, Chairman, President and CEO, and Scott E.King, Co-Founder and Vice President, Geophysics and New Ventures, with an initial equity investment ofapproximately $6.0 million. Shortly thereafter, investors contributed approximately $46.8 million to providea total initial capitalization of approximately $52.8 million. Most of this initial capital was provided by thesame institutional and individual investors who helped capitalize Mr. Foran’s previous company, MatadorPetroleum Corporation.

Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran OilCompany with $270,000 in contributed capital from 17 friends and family members. Foran Oil Companywas later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988.Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it wassold in June 2003 to Tom Brown, Inc. in an all cash transaction for an enterprise value of approximately$388.5 million.

With an average of more than 25 years of oil and natural gas industry experience, our managementteam has extensive expertise in exploring for and developing hydrocarbons in multiple U.S. basins.Members of our management team have participated in the assimilation of numerous lease positions and inthe drilling and completion of hundreds of vertical and horizontal wells in unconventional resource plays.

Since our first well in 2004, we have drilled or participated in drilling 213 wells through September 30,2011, including 83 Haynesville and six Eagle Ford wells. From December 31, 2008 through September 30,2011, we grew our estimated proved reserves from 20.0 Bcfe to 161.8 Bcfe. At September 30, 2011, 35% ofour estimated proved reserves were proved developed reserves and 96% of our estimated proved reserveswere natural gas. We also grew our average daily production by approximately 162% from 9.0 MMcfe perday for the year ended December 31, 2008 to 23.6 MMcfe per day for the year ended December 31, 2010.In addition, as a result of production from new wells that were completed in 2011, our daily production forthe nine months ended September 30, 2011 averaged approximately 42.5 MMcfe per day. We haveachieved this growth while lowering operating costs (consisting of lease operating expenses and productiontaxes and marketing expenses) from $1.91 per Mcfe for the year ended December 31, 2008, to $0.90 perMcfe for the nine months ended September 30, 2011, or a decrease of approximately 53%.

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The following table presents certain summary data for each of our operating areas as of and for thenine months ended September 30, 2011:

ProducingWells

Total IdentifiedDrilling Locations(1)

Estimated Net ProvedReserves

Avg. DailyProduction(MMcfe)Net Acreage Gross Net Gross Net Bcfe(2) % Developed

South Texas:Eagle Ford . . . . . . . . . . . . . . . . . . . 28,906 5.0 3.4 197.0 157.1 8.4 51.0 3.2Austin Chalk . . . . . . . . . . . . . . . . . 14,849 – – 16.0 16.0 – – –

Area Total(3) . . . . . . . . . . . . . . . 28,906 5.0 3.4 213.0 173.1 8.4 51.0 3.2

NW Louisiana/E Texas:Haynesville . . . . . . . . . . . . . . . . . . 14,705 83.0 10.6 545.0 103.9 136.6 25.4 32.1Cotton Valley(4) . . . . . . . . . . . . . . . 23,236 108.0 71.7 60.0 36.0 16.1 100.0 7.0

Area Total(5) . . . . . . . . . . . . . . . 25,477 191.0 82.3 605.0 139.9 152.7 33.3 39.1

SW Wyoming, NE Utah, SE Idaho . . . 135,862 – – – – – – –

SE New Mexico, West Texas . . . . . . . . 7,519 13.0 5.7 – – 0.7 100.0 0.2

Total . . . . . . . . . . . . . . . . . . . . . 197,764 209.0 91.4 818.0 313.0 161.8 34.5 42.5

(1) These locations have been identified for potential future drilling and are not currently producing. In addition, the total net identifieddrilling locations is calculated by multiplying the gross identified drilling locations in an operating area by our working interestparticipation in such locations. At September 30, 2011, these identified drilling locations included 2 gross and 2 net locations to whichwe have assigned proved undeveloped reserves in the Eagle Ford and 95 gross and 15 net locations to which we have assigned provedundeveloped reserves in the Haynesville. We have no proved undeveloped reserves assigned to identified drilling locations in the AustinChalk or Cotton Valley at September 30, 2011.

(2) These estimates were prepared by our engineering staff and audited by independent reservoir engineers, Netherland, Sewell &Associates, Inc.

(3) Some of the same leases cover the net acres shown for the Eagle Ford formation and the Austin Chalk formation, a shallower formationthan the Eagle Ford formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for southTexas. This total includes acreage that we are producing from or that we believe to be prospective for these formations.

(4) Includes shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wellsproducing from the San Miguel formation in Zavala County, Texas.

(5) Some of the same leases cover the net acres shown for the Haynesville formation and the Cotton Valley formation, a shallower formationthan the Haynesville formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage fornorthwest Louisiana/east Texas. This total includes acreage that we are producing from or that we believe to be prospective for theseformations.

At September 30, 2011, our properties included approximately 52,000 gross acres and 29,000 net acresin the Eagle Ford shale play in Atascosa, DeWitt, Dimmit, Karnes, La Salle, Gonzales, Webb, Wilson andZavala Counties in south Texas. We believe that approximately 85% of our Eagle Ford acreage isprospective predominantly for oil or liquids production. In addition, portions of the acreage are alsoprospective for other targets, such as the Austin Chalk, Olmos and Buda, from which we expect to producepredominantly oil and liquids. Approximately 80% of our Eagle Ford acreage is either held by production ornot burdened by lease expirations before 2013. We have begun to explore and develop our Eagle Fordposition and from November 2010 through December 2011, we completed our first seven operated wells inthis area (see “— Recent Developments”). We have identified 197 gross locations and 157 net locations forpotential future drilling on our Eagle Ford acreage. These locations have been identified on aproperty-by-property basis and take into account criteria such as anticipated geologic conditions andreservoir properties, estimated recoveries from nearby wells based on available public data, drillingdensities observed from other operators, estimated drilling and completion costs, spacing and other rulesestablished by regulatory authorities and surface considerations, among others. At September 30, 2011, wehave identified potential drilling locations on approximately 75% of our net Eagle Ford acreage. As we

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explore and develop our Eagle Ford acreage further, we believe it is possible that we may identify additionallocations for drilling. At September 30, 2011, these identified potential future drilling locations in the EagleFord shale play included 2 gross and 2 net locations to which we have assigned proved undevelopedreserves.

In addition, at September 30, 2011, we had approximately 23,000 gross acres and 15,000 net acres inthe Haynesville shale play in northwest Louisiana and east Texas. Based on our analysis of geologic andpetrophysical information (including total organic carbon content and maturity, resistivity, porosity andpermeability, among other information), well performance data and information available to us related todrilling activity and results from wells drilled across the Haynesville shale play, almost 5,500 of our net acresare located in what we believe is the core area of the play. We believe the core area of the play includes thatarea in which the most Haynesville wells have been drilled by operators and from which we anticipatenatural gas recoveries would likely exceed 6 Bcf per well. Just over 90% of our Haynesville acreage is heldby production from the Haynesville or other formations, and we believe much of it is also prospective for theCotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe approximately1,700 of these net acres are prospective for the Middle Bossier shale play.

At September 30, 2011, we have identified 545 gross locations and 104 net locations for potential futuredrilling in our Haynesville acreage. These locations have been identified on a property-by-property basis andtake into account criteria such as anticipated geologic conditions and reservoir properties, estimatedrecoveries from our producing Haynesville wells and other nearby wells based on available public data,drilling densities observed from other operators including on some of our non-operated properties, estimateddrilling and completion costs, spacing and other rules established by regulatory authorities and surfaceconditions, among others. Of the 545 gross locations identified for future drilling, 470 of these locations (53net locations) have been identified within the 5,500 net acres that we believe are located in the core area ofthe Haynesville play. As we explore and develop our Haynesville acreage further, we believe it is possiblethat we may identify additional locations for future drilling. At September 30, 2011, these identified potentialfuture drilling locations in the Haynesville shale play included 95 gross and 15 net locations to which wehave assigned proved undeveloped reserves.

We also have a large unevaluated acreage position in southwest Wyoming and adjacent areas in Utahand Idaho where we began drilling our initial well in February 2011 to test the Meade Peak natural gasshale. We reached a depth of 8,200 feet, approximately 300 feet above the top of the Meade Peak shale,before having operations suspended for several months due to wildlife restrictions. We resumed operationson this initial test well in September 2011 and completed drilling and coring operations on this well inNovember 2011. In addition, we have leasehold interests in the Delaware and Midland Basins in southeastNew Mexico and west Texas where we are developing new oil and natural gas prospects.

We are active both as an operator and as a co-working interest owner with larger industry participantsincluding affiliates of Chesapeake Energy Corporation, EOG Resources, Inc., Royal Dutch Shell plc andothers. Of the 213 gross wells we have drilled or participated in drilling, we drilled approximately half of thesewells as the operator. At September 30, 2011, we were the operator for approximately 80% of our Eagle Fordand 70% of our Haynesville acreage, including approximately 22% of our acreage in what we believe is thecore area of the Haynesville play. A large portion of our acreage in that core area is operated by a subsidiary ofChesapeake Energy Corporation. We also operate all of our acreage in southwest Wyoming and the adjacentareas of Utah and Idaho, as well as the vast majority of our acreage in southeast New Mexico and west Texas.

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Our net proceeds from this offering, after repaying the then outstanding borrowings under ourrevolving credit agreement ($123.0 million at January 27, 2012, excluding outstanding letters of credit),when taken together with our cash flows and future potential borrowings under our credit agreement, will beused to fund our 2012 capital expenditure requirements and for potential acquisitions of interests andacreage (none of which have been identified). As a result of our anticipated increases in production andreserves, we expect to have a sufficient increase in our cash flows from operations during the year endingDecember 31, 2012, as compared to our cash flows from operations in prior periods, as well as a sufficientincrease in the borrowing base under our credit agreement to help fund our 2012 capital expenditure budget.A majority of our anticipated increase in cash flows during the year ending December 31, 2012 is expectedto come from our exploration activities on unproved properties at September 30, 2011 in the Eagle Fordshale play assuming such exploration activities are successful. These anticipated increases in our cash flowsfrom operations are based upon current oil and natural gas prices and the hedges we currently have in place.If our exploration activities result in less cash flows than anticipated, we may seek additional sources ofcapital, including through borrowings under our credit agreement (assuming availability under ourborrowing base) or from the issuance of additional equity or debt securities. In addition, we may modify ourplanned capital expenditure budget for 2012 accordingly. Exploration activities are subject to a number ofrisks and uncertainties that could impact our ability to sufficiently increase our reserves, cash flows fromoperations and borrowing base under our credit agreement. See “Risk Factors — Our Exploration,Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed OurCash Flows From Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capitalon Satisfactory Terms, Which Could Adversely Affect Our Future Growth” and “— Drilling for andProducing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with ManyUncertainties That Could Adversely Affect Our Business.” We anticipate that we may need to access futureborrowings under our credit agreement within 30 days following completion of this offering to fund aportion of our 2012 capital expenditure requirements in excess of amounts available from our cash flowsand the net proceeds of this offering. See “Use of Proceeds.”

The following table presents our 2012 anticipated capital expenditure budget of approximately$313.0 million segregated by target formations and by whether the wells are considered to be exploration ordevelopment wells.

2012 Anticipated Drilling2012 Anticipated Capital

Expenditure Budget

Gross Wells(1) Net Wells(1) (in millions)(2)

Exploration Development Total Exploration Development Total Exploration Development Total

South TexasEagle Ford . . . . . . . . . . . . . . . . . . 13.0 15.0 28.0 11.8 13.8 25.6 $122.3 $134.9 $257.2Austin Chalk . . . . . . . . . . . . . . . . 2.0 — 2.0 2.0 — 2.0 11.3 — 11.3

Area Total . . . . . . . . . . . . . . . . . . 15.0 15.0 30.0 13.8 13.8 27.6 133.6 134.9 268.5NW Louisiana / E TexasHaynesville . . . . . . . . . . . . . . . . . . 6.0 19.0 25.0 0.2 1.3 1.5 1.9 11.6 13.5Cotton Valley . . . . . . . . . . . . . . . . — — — — — — — — —

Area Total . . . . . . . . . . . . . . . . . . 6.0 19.0 25.0 0.2 1.3 1.5 1.9 11.6 13.5SW Wyoming, NE Utah, SE

Idaho . . . . . . . . . . . . . . . . . . . . 1.0 — 1.0 0.4 — 0.4 2.5 — 2.5(3)

SE New Mexico, West Texas . . . — — — — — — — — —Other . . . . . . . . . . . . . . . . . . . . . . N/A N/A N/A N/A N/A N/A 25.0 3.5 28.5(4)

Total . . . . . . . . . . . . . . . . . . . . . . . 22.0 34.0 56.0 14.4 15.1 29.5 $163.0 $150.0 $313.0

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(1) Includes wells we currently expect to drill and complete as operator, plus those wells in which we currently plan to participate as a non-operator in 2012.

(2) Our capital expenditure budget is based on our net working interests in the properties.

(3) We have a carried interest for $5.0 million of the cost of this well presuming the election of our joint venture partner to participate in thedrilling of this well.

(4) Includes $20.0 million to acquire additional leasehold interests primarily prospective for oil and liquids production in southeastNew Mexico and west Texas. Also includes $6.5 million in leasehold, seismic and infrastructure expenditures for the Eagle Ford.

Although we intend to allocate a portion of our 2012 capital expenditure budget to financingexploration, development and acquisition of additional interests in the Haynesville shale play, we currentlyintend to allocate approximately 84% of our 2012 capital expenditure budget to the exploration,development and acquisition of additional interests in the Eagle Ford shale play. Including these anticipatedcapital expenditures in the Eagle Ford shale play, we plan to dedicate about 94% of our 2012 anticipatedcapital expenditure budget to opportunities prospective for oil and liquids production. While we havebudgeted $313.0 million for 2012, the aggregate amount of capital we will expend may fluctuate materiallybased on market conditions and our drilling results. Since at September 30, 2011, just over 90% of ourHaynesville acreage was held by production and approximately 80% of our Eagle Ford acreage was eitherheld by production or not burdened by lease expirations before 2013, we possess the financial flexibility toallocate our capital when we believe it is economical and justified.

Recent Developments

Recent Results

At January 16, 2012, we had drilled an aggregate of 11 Eagle Ford horizontal wells as operator. Sevenof these wells have been completed and are producing. One of these wells, the Martin Ranch #8H in LaSalle County, Texas, is currently undergoing completion operations, and we anticipate that two additionalwells, the Martin Ranch #6H and the Martin Ranch #7H, will be completed in the near future. The MatadorSickenius ORCA #1H in Karnes County, Texas is also expected to be completed during the first quarter of2012. At January 16, 2012, we had two contracted drilling rigs operating in the Eagle Ford play: one in LaSalle County and the second in Karnes County.

For the month of December 2011, our daily production averaged approximately 43.4 MMcfe per day,including 39.8 MMcf of natural gas per day and 600 Bbl of oil per day. During the first 11 days of January2012, our daily production averaged approximately 53.2 MMcfe per day, including 42.4 MMcf of naturalgas per day and 1,800 Bbl of oil per day.

In December 2011, four of our Eagle Ford wells, the Martin Ranch #2H, #3H and #5H in La SalleCounty, Texas and the Lewton #1H in DeWitt County, Texas, began producing. In January 2012, weestimated that these four wells and six associated proved undeveloped locations increased our proved oiland natural gas reserves by approximately 2.8 million barrels of oil and 4.2 Bcf of natural gas as ofDecember 31, 2011. These incremental estimates of proved reserves were prepared by our engineering staffand have been reviewed for their reasonableness by Netherland, Sewell & Associates, Inc., our independentreservoir engineers. These estimates were determined in accordance with guidelines established by theSecurities and Exchange Commission for estimating and reporting oil and natural gas reserves. AtJanuary 16, 2012, we had not yet completed the estimates of our proved oil and natural gas reserves for theremainder of our properties at December 31, 2011.

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Other Developments

Between November 2011 and January 2012, we entered into various costless collars to mitigate ourexposure to oil price volatility and enhance predictability of our cash flows in 2012 and 2013. As ofJanuary 13, 2012, we have hedged a total of 1,060,000 Bbl of oil for 2012 and a total of 780,000 Bbl of oilfor 2013. For 2012, all collars have a price floor of $90.00/Bbl and price ceilings that range from$104.20/Bbl to $113.75/Bbl. For 2013, all collars have price floors of $85.00/Bbl or $90.00/Bbl and priceceilings that range from $102.25/Bbl to $110.40/Bbl. These costless collars may limit our potential gains ifoil prices rise above the specified price ceilings. For additional information, see “Risk Factors—HedgingTransactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in Financial Losses”and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Exposure.”

In December 2011, we amended and restated our senior secured revolving credit agreement. Thisamendment increased the maximum facility amount from $150 million to $400 million. Borrowings arelimited to the lesser of $400 million or the borrowing base, which will be $100 million immediatelyfollowing this offering. On January 25, 2012, we borrowed an additional $10.0 million under this agreementwhich brought our total borrowings to $123.0 million.

In November and December 2011, we completed three additional operated Eagle Ford horizontalwells, the Martin Ranch #2H, #3H and #5H in northeastern La Salle County, Texas. During initial flowtests on these wells, the Martin Ranch #2H tested at approximately 1,310 Bbls of oil and 1.8 MMcf ofnatural gas per day, the Martin Ranch #3H tested at approximately 620 Bbls of oil and 0.5 MMcf of naturalgas per day, and the Martin Ranch #5H tested at approximately 810 Bbls of oil and 0.6 MMcf of natural gasper day. All three wells were turned to sales in late December 2011. We are the operator and have a 100%working interest in these three wells.

In August 2011, we completed our fourth operated Eagle Ford horizontal well, the Lewton #1H inDeWitt County, Texas. This well began producing to sales in late December 2011, and in early January2012, the well was producing approximately 2.7 MMcf of natural gas and 600 Bbls of condensate per day.We are the operator of this well and paid 100% of the costs to drill and complete the well. We will receive85% of the revenues attributable to the working interest in the well until we have recovered all of ouracquisition, drilling and completion costs, after which time, our partner will receive 50% of the revenuesattributable to the working interest in the well and we and our partner will each maintain a 50% workinginterest in the well.

Between March and July 2011, we acquired leasehold interests in approximately 6,300 gross and 4,800net acres in DeWitt, Karnes, Wilson and Gonzales Counties, Texas in the Eagle Ford shale play from OrcaICI Development, JV. We believe that all of this acreage is in an oil and liquids prone area of the EagleFord play. We believe that the acreage in Wilson and Gonzales Counties and a portion of DeWitt Countywill be prospective for oil and liquids from the Austin Chalk formation in addition to the Eagle Ford. Wepaid approximately $31.5 million to acquire this acreage. We currently own a 50% working interest in theacreage (approximately 2,800 gross and 1,400 net acres) in DeWitt County and are the operator. Wecurrently own a 100% working interest in the acreage (approximately 3,500 gross and 3,400 net acres) inKarnes, Wilson and Gonzales Counties and are the operator.

In March 2011, first sales of natural gas began from our Williams 17 H#1 well, located in what webelieve to be the core area of the Haynesville shale play in northwest Louisiana. We began producing this

7

well at a constrained rate of about 10.0 MMcf of natural gas per day. During November 2011, this wellproduced at an average daily rate of 4.5 MMcf of natural gas per day, and through November 30, 2011, hadproduced approximately 1.7 Bcf of natural gas. We are the operator and have a 100% working interest and afavorable 87.5% net revenue interest in this well.

In February 2011, we completed our third operated Eagle Ford horizontal well, the Affleck #1H, ineastern Dimmit County, Texas. This well tested at approximately 415 Bbls of oil and 5.4 MMcf of naturalgas per day during an initial flow test. During November 2011, this well produced at an average daily rateof 0.9 MMcf of natural gas and 70 Bbls of oil per day. We are the operator and have a 100% workinginterest in this well.

In January 2011, we completed a private placement offering of 1,922,199 shares of our Class Acommon stock at $11.00 per share for an aggregate amount of $21,144,189.

In January 2011, we completed our second operated Eagle Ford horizontal well, the MartinRanch #1H, in northeastern La Salle County, Texas. First sales of oil and natural gas from this well beganin late March at approximately 700 Bbls of oil and 350 Mcf of natural gas per day. During November 2011,the well produced at an average daily rate of approximately 520 Bbls of oil and 0.6 MMcf of natural gas perday, and through November 30, 2011, had produced a total of approximately 111,000 Bbls of oil and135 MMcf of natural gas. We are the operator and have a 100% working interest in this well.

In January 2011, first sales of oil and natural gas began from our first operated Eagle Ford horizontalwell, the JCM Jr. Minerals #1H, in southern La Salle County, at approximately 3.4 MMcf of natural gas and135 Bbls of condensate per day. During November 2011, the well produced at an average daily rate ofapproximately 0.6 MMcf of natural gas and 12 Bbls of condensate per day, and through November 30,2011, had produced a total of approximately 416 MMcf of natural gas and 10,900 Bbls of condensate. Weare the operator and have a 100% working interest in this well.

In January 2011, we completed our first horizontal Cotton Valley well, the Tigner Walker H#1-Alt., inDeSoto Parish, Louisiana. First sales of natural gas from this well began in late January at approximately4.6 MMcf of natural gas per day. During November 2011, the well produced at an average daily rate ofapproximately 1.9 MMcf of natural gas per day, and through November 30, 2011, had produced a total ofapproximately 900 MMcf of natural gas. We are the operator and have a 100% working interest in this wellsubject to a reversionary interest at payout.

On December 31, 2010, first sales of natural gas began from our L.A. Wildlife H#1 Alt. horizontalwell, located in what we believe to be the core area of the Haynesville shale play in northwest Louisiana.We began producing this well at a constrained rate of about 10.0 MMcf of natural gas per day. DuringNovember 2011, the well produced at an average daily rate of approximately 10.0 MMcf of natural gas perday, and through November 30, 2011, had produced a total of approximately 3.2 Bcf of natural gas. We arethe operator and have a 95% working interest in this well.

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Business Strategies

Our goal is to increase shareholder value by building reserves, production and cash flows at anattractive return on invested capital. We plan to achieve our goal by executing the following strategies:

• Focus Exploration and Development Activity on Our Eagle Ford and Haynesville Shale Assets.

We have established core acreage positions in the Eagle Ford and Haynesville shale plays, whichwe believe are two of the most active and economically viable shale plays in North America.Although we intend to allocate a portion of our 2012 capital expenditure budget to financingexploration, development and acquisition of additional interests in the Haynesville shale play, wecurrently intend to allocate approximately 84% of our 2012 capital expenditure budget to theexploration, development and acquisition of additional interests in the Eagle Ford shale play.Since just over 90% of our Haynesville acreage was held by production and approximately 80%of our Eagle Ford acreage was either held by production or not burdened by lease expirationsbefore 2013 at September 30, 2011, we have the flexibility to develop our acreage in a disciplinedmanner in order to maximize the resource recovery from these assets. We believe the economicsfor development in these two areas are attractive at current commodity prices.

• Identify, Evaluate and Exploit Oil Plays to Create a More Balanced Portfolio.

Although most of our current proved reserves are classified as natural gas, we have beenevaluating various oil plays to find and execute upon opportunities that would fit well with ourexploration and operating strategies. We believe our interests in the Eagle Ford shale play willenable us to create a more balanced commodity portfolio through the drilling of locations that areprospective for oil and liquids. We believe oil and liquids opportunities represent about 94% ofour anticipated 2012 capital expenditure budget. We expect to continue to create and acquireadditional prospects and opportunities for the exploration and production of oil and liquids.

• Pursue Opportunistic Acquisitions.

We believe our management team’s familiarity with our key operating areas and its contacts withthe operators and mineral owners in those regions enable us to identify high-return opportunitiesat attractive prices. We actively pursue opportunities to acquire unproved and unevaluatedacreage, drilling prospects and low-cost producing properties within our core areas of operationswhere we have operational control and can enhance value and performance. We view theseacquisitions as an important component of our business strategy and intend to selectively makeacquisitions on attractive terms that complement our growth and help us achieve economies ofscale.

• Maintain Our Financial Discipline.

As an operator, we leverage advanced technologies and integrate the knowledge, judgment andexperience of our management and technical teams. We believe our team demonstrates financialdiscipline that is achieved by our approach to evaluating and analyzing prospects and priordrilling and completion results before allocating capital and is reflected in the improvements ourteam has attained on reducing unit costs. When we are not the operator, we proactively engagewith the operators in an effort to ensure similar financial discipline. Additionally, we conduct ourown internal geological and engineering studies on these prospects and provide input on thedrilling, completion and operation of many of these non-operated wells pursuant to our

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agreements and relationships with the operators. Through these methods and practices, we believewe are well-positioned to control the expenses and timing of development and exploitation of ourproperties.

• Maintain Proactive and Ongoing Relationships with Other Industry Participants.

We believe maintaining proactive and ongoing relationships with other industry operators andvendors enhances our understanding of the shale plays and allows us to leverage their expertisewithout having to commit substantial capital. We currently participate in various drilling activitieswith larger industry participants, including affiliates of Chesapeake Energy Corporation, EOGResources, Inc., Royal Dutch Shell plc and others. We are also active participants in threeindustry shale consortia: the North American Gas Shale, Haynesville and Bossier Shale and EagleFord Shale consortia organized by Core Laboratories, LP. As active members in variousprofessional societies, our staff and board members also regularly interact on a professional basiswith other industry participants.

Competitive Strengths

We believe our prior success is, and our future performance will be, directly related to the followingcombination of strengths that will enable us to implement our strategies:

• High Quality Asset Base in Attractive Areas.

We have key acreage positions in active areas of the Eagle Ford and Haynesville shale plays. Webelieve our assets in these plays are characterized by low geological risk and similar repeatabledrilling opportunities that we expect will result in a predictable production growth profile. Thecommodity mix of our production and reserves is expected to become more balanced as a result ofour planned activities on our Eagle Ford and Austin Chalk acreage, which is located in oil andliquids prone areas of the plays. In addition to the Haynesville shale, our east Texas and northLouisiana assets have multiple, recognized geologic horizons, including the Middle Bossier shale,Cotton Valley and Hosston (Travis Peak) formations. We also believe there is additional resourcepotential in our oil and natural gas prospects in southeast New Mexico and west Texas, along withour natural gas prospects in southwest Wyoming and adjacent areas in Utah and Idaho.

• Large, Multi-year, Development Drilling Inventory.

Within our northwest Louisiana/east Texas and south Texas regions, we have identified 818 grossand 313 net drilling locations, including 197 gross and 157 net locations in the Eagle Ford shale playand 545 gross and 104 net locations in the Haynesville shale play. At September 30, 2011, theseidentified drilling locations included 2 gross and 2 net locations to which we have assigned provedundeveloped reserves in the Eagle Ford shale play and 95 gross and 15 net locations to which wehave assigned proved undeveloped reserves in the Haynesville shale play. We have identified 28gross and 26 net locations in the Eagle Ford shale play and 25 gross and 2 net locations in theHaynesville shale play that we expect to drill in 2012, the completion of which would representapproximately 14% and 5% of our identified gross drilling locations in these two areas atSeptember 30, 2011, respectively. Additionally, we expect to identify and develop additionallocations across our broad exploration portfolio as we evaluate our Cotton Valley, Austin Chalk,Meade Peak and Delaware and Midland Basin assets. We believe our multi-year, identified drillinginventory and exploration portfolio provide visible near-term growth in our production and reserves,and highlight the long-term resource potential across our asset base.

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• Financial Flexibility to Fund Expansion.

Historically, we have maintained financial flexibility by obtaining capital through shareholderinvestments and our operational cash flows while having access to additional borrowings, whichhas allowed us to take advantage of acquisition opportunities as they arise. At September 30,2011, on an as adjusted basis to give effect to this offering and our use of proceeds, we expect tohave at least $98.7 million available for borrowings under our credit agreement after giving effectto outstanding letters of credit. Excluding any possible acquisitions, we expect to maintain ourcurrent financial flexibility by funding our entire 2012 capital expenditure budget through the netproceeds we receive from this offering, together with our cash flows and future potentialborrowings under our credit agreement. As a result of our anticipated increases in production andreserves, we expect to have a sufficient increase in our cash flows from operations during the yearending December 31, 2012, as compared to our cash flows from operations in prior periods, aswell as a sufficient increase in the borrowing base under our credit agreement to help fund our2012 capital expenditure budget. A majority of our anticipated increase in cash flows during theyear ending December 31, 2012 is expected to come from our exploration activities on unprovedproperties at September 30, 2011 in the Eagle Ford shale play assuming such explorationactivities are successful. These anticipated increases in our cash flows from operations are basedupon current oil and natural gas prices and the hedges we currently have in place. If ourexploration activities result in less cash flows than anticipated, we may seek additional sources ofcapital, including through borrowings under our credit agreement (assuming availability under ourborrowing base) or from the issuance of additional equity or debt securities. In addition, we maymodify our planned capital expenditure budget for 2012 accordingly. Exploration activities aresubject to a number of risks and uncertainties that could impact our ability to sufficiently increaseour reserves, cash flows from operations and borrowing base under our credit agreement. See“Risk Factors — Our Exploration, Development and Exploitation Projects Require SubstantialCapital Expenditures That May Exceed Our Cash Flows From Operations and PotentialBorrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, WhichCould Adversely Affect Our Future Growth” and “— Drilling for and Producing Oil and NaturalGas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties ThatCould Adversely Affect Our Business.” We anticipate that we may need to access futureborrowings under our credit agreement within 30 days following completion of this offering tofund a portion of our 2012 capital expenditure requirements in excess of amounts available fromour cash flows and the net proceeds of this offering. Our availability of capital as described abovewill also allow us to maintain our competitiveness in seeking to acquire additional oil and naturalgas properties as opportunities arise. A strong balance sheet and interest savings should alsoreduce unit costs and increase profitability. In addition, since a large portion of our Eagle Fordand Haynesville acreage was held by production at September 30, 2011, we have the financialflexibility to allocate our capital when we believe it is economical and justified.

• Experienced and Incentivized Management, Technical Team and Board.

Our management and technical teams possess extensive oil and natural gas expertise with anaverage of over 25 years of relevant industry experience from companies such as MatadorPetroleum Corporation, S. A. Holditch & Associates, Inc., Schlumberger Limited, Conoco andARCO, and we believe they have a demonstrated record of growth and financial discipline overmany years. The management team has experience in drilling and completing hundreds of vertical

11

and horizontal wells in unconventional resource plays, including the Cotton Valley, Bossier,Wilcox/Vicksburg, Austin Chalk, Haynesville and Eagle Ford plays. Our management team’sexperience is complemented by a strong technical team with deep knowledge of advancedgeophysical, drilling and completion technologies whose members are active in their professionalsocieties. Additionally, we have a group of board members and special advisors with considerableexperience and expertise in the oil and natural gas industry and in managing other successfulenterprises who provide insight and perspective regarding our business and the evaluation,exploration, engineering and development of our prospects. In addition to its considerableexperience, our management team currently owns and will continue to own a significant directownership interest in us immediately following the completion of this offering. We believe ourmanagement team’s direct ownership interest, as well as its ability to increase its holdings overtime through our long-term incentive plan, aligns management’s interests with those of ourshareholders.

• Extensive Geologic, Engineering and Operational Experience in Unconventional Reservoir Plays.

The individuals on our technical team are highly experienced in analyzing unconventionalreservoir plays and in horizontal drilling, completion and production operations in a number ofgeographic areas. Our geologists have extensive experience in analyzing unconventional reservoirplays throughout the United States, including our principal areas of interest, by using the latestimaging technology, such as 2-D and 3-D seismic interpretation, and petrophysical analysis. Inaddition, our technical team has been directly involved in over 26 different horizontal well drillingand/or operations programs in both onshore and offshore formations located in the United Statesand abroad. Our team’s diverse and broad horizontal drilling experience includes most, if not all,techniques used in modern day drilling. Additionally, our team has in-depth experience withvarious horizontal completion techniques and their applications in multiple unconventional plays.We intend to leverage our team’s geological expertise and horizontal drilling and completionexperience to develop and exploit our large, multi-year development drilling inventory.

• Multi-Disciplined Approach to New Opportunities.

Our process for evaluating and developing new oil and natural gas prospects is a result of what webelieve is an organizational philosophy that is dedicated to a systematic, multi-disciplinaryapproach to new opportunities with an emphasis on incorporating petroleum systems,geosciences, technology and finance into the decision-making process. We recognize theimportance of consulting multiple individuals in our organization across all disciplines and alllevels of responsibility prior to making exploration, acquisition or development decisions and theformulation of key criteria for successful exploration and development projects in any given playto enhance our decision-making. We also conduct a post-completion review of our majordecisions to determine what we did right and where we need to improve. At times, this approachresults in a decision to accelerate our drilling program or expand our positions in certain areas.Other times, this approach results in a decision to mitigate risk associated with our explorationand development programs by sharing operational risks and costs with other industry participantsor exiting an area altogether. We believe this multi-disciplined approach underpins our trackrecord of value creation and represents the best way to deliver consistent, year-over-year results toour shareholders.

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Certain Risk Factors

An investment in our common stock involves risks that include the speculative nature of oil and naturalgas exploration and production, competition, volatile oil and natural gas prices and other material factors. Inparticular, the following considerations may offset our competitive strengths or have a negative effect onboth our business strategy as well as on activities on our properties, which could cause a decrease in theprice of our common stock and result in a loss of all or a portion of your investment:

• Our success is dependent on the prices of oil and natural gas. Low oil or natural gas prices or thesubstantial volatility in these prices may adversely affect our financial condition and our ability tomeet our capital expenditure requirements and financial obligations;

• Drilling for and producing oil and natural gas are high-risk activities with many uncertainties thatcould adversely affect our business, financial condition, results of operations and cash flows;

• Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil andnatural gas we will receive, and significant inaccuracies in these reserve estimates or underlyingassumptions will materially affect the quantities and present value of our reserves;

• Our exploration, development and exploitation projects require substantial capital expenditures thatmay exceed our cash flows from operations and potential borrowings, and we may be unable toobtain needed capital on satisfactory terms, which could adversely affect our future growth;

• The unavailability or high cost of drilling rigs, completion equipment and services, supplies andpersonnel, including hydraulic fracturing equipment and personnel, could adversely affect ourability to establish and execute exploration and development plans within budget and on a timelybasis, which could have a material adverse effect on our financial condition, results of operationsand cash flows;

• Because our reserves and production are concentrated in a small number of properties, problems inproduction and markets relating to any property could have a material impact on our business;

• Drilling locations that we decide to drill may not yield oil or natural gas in commercially viablequantities;

• We may have accidents, equipment failures or mechanical problems while drilling or completingwells or in production activities, which could adversely affect our business;

• We have limited control over activities on properties we do not operate;

• Approximately 67% of our total proved reserves at September 30, 2011 consisted of undevelopedand developed non-producing reserves, and those reserves may not ultimately be developed orproduced;

• Our success depends, to a large extent, on our ability to retain our key personnel, including ourChairman of the Board, Chief Executive Officer and President, the members of our board ofdirectors and our special board advisors, and the loss of any key personnel, board member orspecial board advisor could disrupt our business operations; and

• If any of the material weaknesses previously identified by our independent registered publicaccountants persist or if we fail to establish and maintain effective internal control over financialreporting in the future, our ability to accurately report our financial results could be adverselyaffected.

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For a discussion of these risks and other considerations that could negatively affect us, including risksrelated to this offering and our common stock, see “Risk Factors” beginning on page 23 and “CautionaryNote Regarding Forward-Looking Statements.”

Organizational Structure

Matador Resources Company was formed as a Texas corporation in July 2003. Pursuant to the terms ofthe corporate reorganization that was completed on August 9, 2011, former Matador Resources Company,now known as MRC Energy Company, became a wholly owned subsidiary of current Matador ResourcesCompany, formerly known as Matador Holdco, Inc. In connection with the reorganization, former MatadorResources Company changed its corporate name to MRC Energy Company, and Matador Holdco, Inc.changed its corporate name to Matador Resources Company.

The following diagram indicates our ownership structure and organizational structure after givingeffect to our corporate reorganization and this offering. The shareholder ownership information set forthbelow is based on the beneficial ownership of our common stock after consummation of this offering basedon the number of shares beneficially owned by our current shareholders at January 27, 2012.

Matador ResourcesCompany

(formerly known asMatador Holdco, Inc.)

NYSE: MTDR

MRC Energy Company(formerly known asMatador Resources

Company)

Matador ProductionCompany

MRC Permian Company MRC Rockies Company

Longwood Gathering andDisposal Systems, LP

0.01% 99.99%

Current Management

12.7%

Current InstitutionalInvestors29.7%

Other CurrentShareholders33.2%

New Public Shareholders

24.4%

Longwood Gathering andDisposal Systems GP,

Inc.

14

Corporate Information

We are headquartered in Dallas, Texas. Our executive offices and mailing address are at One LincolnCentre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. Our telephone number is (972) 371-5200. Weexpect to have an operational website that meets Securities and Exchange Commission, or SEC, and NewYork Stock Exchange, or NYSE, requirements concurrently with, or prior to, the completion of thisoffering. Information on our website or any other website is not and will not be incorporated by referenceherein and does not and will not constitute a part of this prospectus.

15

The Offering

Issuer Matador Resources Company

Selling shareholders See “Principal and Selling Shareholders.”

Common stock offered by us 11,666,667 shares (12,366,667 shares if the underwriters’over-allotment is exercised in full)

Common stock offered by sellingshareholders

1,666,667 shares (2,966,667 shares if the underwriters’over-allotment is exercised in full)

Common stock outstanding after offering 54,719,860 shares (55,419,860 shares if the underwriters’over-allotment is exercised in full)

The number of shares to be outstanding after this offeringis based on 43,053,193 shares of our common stockoutstanding at January 16, 2012. This number excludes4,000,000 additional shares that are authorized for futureissuance under our equity incentive plan and 739,500additional shares that may be issued subsequent to theoffering pursuant to outstanding stock options.

Over-allotment option We and the selling shareholders have granted theunderwriters a 30-day option to purchase up to anaggregate of 700,000 and 1,300,000 additional shares ofour common stock, respectively, to cover any over-allotments.

Use of proceeds We estimate that our net proceeds from this offering willbe approximately $127.6 million, or $135.4 million if theunderwriters exercise their over-allotment option in full,in each case after deducting the underwriting discountsand commissions and estimated offering expenses.

We intend to use the net proceeds we receive from thisoffering to repay the then outstanding borrowings under ourcredit agreement ($123.0 million outstanding at January 27,2012, excluding outstanding letters of credit). Theremaining net proceeds will be used to fund a portion of ouranticipated 2012 capital expenditure budget. We will notreceive any of the proceeds from the sale of shares of ourcommon stock by the selling shareholders. See “Use ofProceeds.”

Affiliates of certain of the underwriters are lenders underour senior secured revolving credit agreement and,accordingly, will receive more than 5% of the proceedsfrom this offering. See “Use of Proceeds” and“Underwriters — Conflicts of Interest.”

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Dividend policy We do not anticipate paying any cash dividends on ourcommon stock.

Risk factors You should carefully read and consider the informationbeginning on page 23 of this prospectus set forth underthe heading “Risk Factors” and all other information setforth in this prospectus before deciding to invest in ourcommon stock.

New York Stock Exchange Symbol MTDR

17

Summary Financial, Reserves and Operating Data

You should read the following summary financial, reserves and operating data in conjunction with“Selected Historical Consolidated and Other Financial Data,” “Management’s Discussion and Analysis ofFinancial Condition and Results of Operations,” “Business” and our audited and unaudited historicalconsolidated financial statements and related notes thereto included elsewhere in this prospectus. Thefinancial information included in this prospectus may not be indicative of our future results of operations,financial position and cash flows.

Financial Data

The following tables set forth summary historical consolidated financial information for the company andits subsidiaries. The historical consolidated financial information is derived from the audited consolidatedfinancial statements for the company and its subsidiaries at and for the years ended December 31, 2010, 2009and 2008 and the unaudited condensed consolidated financial statements for the company and its subsidiariesat and for the nine months ended September 30, 2011 and 2010. The balance sheet data has also been adjustedto reflect the estimated net proceeds to be received by us from this offering. The audited consolidated financialstatements for the company and its subsidiaries at and for the years ended December 31, 2010, 2009 and 2008and the unaudited condensed consolidated financial statements for the company and its subsidiaries at and forthe nine months ended September 30, 2011 and 2010 are contained elsewhere in this prospectus. Ourconsolidated financial statements for the years ended December 31, 2010, 2009 and 2008 were audited byGrant Thornton LLP.

Year Ended December 31,Nine Months Ended

September 30,

2010 2009 2008 2011 2010

(Unaudited) (Unaudited)

(In thousands, except per share data)Statement of operations data:Revenues:

Oil and natural gas revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $34,042 $ 19,039 $ 30,645 $ 52,009 $25,182Realized gain (loss) on derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,299 7,625 (1,326) 4,237 2,988Unrealized gain (loss) on derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . 3,139 (2,375) 3,592 1,534 5,813

Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42,480 24,289 32,911 57,780 33,983Expenses:

Production taxes and marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,982 1,077 1,639 4,801 1,235Lease operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,284 4,725 4,667 5,639 3,801Depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . 15,596 10,743 12,127 22,578 10,931Accretion of asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . 155 137 92 158 107Full-cost ceiling impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 25,244 22,195 35,673 –General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,702 7,115 8,252 9,395 6,793

Total expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32,719 49,041 48,972 78,244 22,867Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,761 (24,752) (16,061) (20,464) 11,116Other:

Other (expense) income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137 402 139,962(1) (213) 300

Income (loss) before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,898 (24,350) 123,901 (20,677) 11,416Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,377 $(14,425) $103,878 $(13,725) $ 7,373

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September 30,

2010 2009 2008 2011 2010

(Unaudited) (Unaudited)

(In thousands, except per share data)Earnings (loss) per share (basic) (2)

Class A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.15 $ (0.37) $ 2.50 $ (0.33) $ 0.18Class B(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.42 $ (0.10) $ 2.77 $ (0.13) $ 0.38

Weighted average common shares outstanding (basic) . . . . . . . . . . . . . . . . . . 41,037 40,123 41,385 42,702 40,880Class A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40,007 39,093 40,355 41,671 39,849Class B(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,031 1,031 1,031 1,031 1,031

(1) Increase in other income was primarily due to gain on unproved and unevaluated property dispositions in 2008.

(2) At September 30, 2011, we had 1,030,700 shares of Class B common stock issued and outstanding. All shares of Class B common stockwill automatically convert on a one-for-one basis into shares of Class A common stock upon the consummation of this offering pursuantto the terms of our certificate of formation. If the Class B common stock were converted at the applicable date, the earnings per sharewould not be materially different than the Class A earnings per share.

At December 31, At September 30,

2010 2009 2008 2011 2010

ActualAs

Adjusted(1)

(In thousands) (Unaudited) (Unaudited) (Unaudited)Balance sheet data:Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 21,060 $104,230 $150,768 $ 7,768 $ 14,883 $ 38,618Certificates of deposit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,349 15,675 20,782 2,085 2,085 7,429Net property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . 303,880 142,078 125,261 350,279 388,279 227,052

Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 346,382 277,400 314,539 383,244 428,359 291,423Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30,097 8,868 35,475 50,102 25,102 19,396Long term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34,408 4,210 2,059 64,604 4,604 8,125Total shareholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . $281,877 $264,321 $277,005 $268,538 $398,653 $263,902

(1) As adjusted to give effect to (a) this offering (assuming aggregate net proceeds of $127.6 million are received by us), (b) the applicationof the net proceeds to be received by us to repay the then outstanding borrowings under our credit agreement ($123.0 million lessoutstanding letters of credit), (c) $38.0 million being added to property and equipment reflecting the use of $38.0 million in additionalborrowings under our credit agreement between September 30, 2011 and January 27, 2012, (d) the balance of the net proceeds from thisoffering being added to cash and cash equivalents to fund a portion of our 2012 capital expenditure budget and (e) the proceeds to bereceived by us as a result of the issuance of 285,000 shares of common stock to certain holders of stock options prior to theconsummation of this offering in connection with the exercise of their stock options at an exercise price of $9.00 per share.


September 30,

2010 2009 2008 2011 2010

(In thousands) (Unaudited) (Unaudited)Other financial data:Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . $ 27,273 $ 1,791 $ 25,851 $ 34,443 $ 21,390Net cash (used in) provided by investing activities . . . . . . . . . . . . . . . . . (147,334) (49,415) 115,481 (107,772) (78,718)

Oil and natural gas properties capital expenditures . . . . . . . . . . . . . (159,050) (54,244) (104,119) (104,733) (86,031)Expenditures for other property and equipment . . . . . . . . . . . . . . . (1,610) (307) (3,012) (3,303) (934)

Net cash provided by (used in) financing activities . . . . . . . . . . . . . . . . . 36,891 1,086 419 60,037 (8,284)Adjusted EBITDA(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 23,635 $ 15,184 $ 18,411 $ 37,550 $ 17,133

(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA toour net income and net cash provided by operating activities, see “— Non-GAAP Financial Measures” below.

Non-GAAP Financial Measures

We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion,depreciation and amortization, property impairments, unrealized derivative gains and losses, non-recurring

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income and expenses and non-cash stock-based compensation expense, including stock option and grantexpense and restricted stock grants. Adjusted EBITDA is not a measure of net income or cash flows asdetermined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used bymanagement and external users of our consolidated financial statements, such as industry analysts,investors, lenders and rating agencies. “GAAP” means Generally Accepted Accounting Principles.

Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operatingperformance and compare the results of operations from period to period without regard to our financingmethods or capital structure. We exclude the items listed above from net income (loss) in calculatingAdjusted EBITDA because these amounts can vary substantially from company to company within ourindustry depending upon accounting methods and book values of assets, capital structures and the methodby which the assets were acquired.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income orcash flows from operating activities as determined in accordance with GAAP or as an indicator of ouroperating performance or liquidity. Certain items excluded from Adjusted EBITDA are significantcomponents of understanding and assessing a company’s financial performance, such as a company’s costof capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures ofanother company because all companies may not calculate Adjusted EBITDA in the same manner. Thefollowing table presents our calculation of Adjusted EBITDA and reconciliation of Adjusted EBITDA tothe GAAP financial measures of net income (loss) and net cash provided by operating activities,respectively.

Year Ended December 31,

Nine MonthsEnded

September 30,

2010 2009 2008 2011 2010

(In thousands)Unaudited Adjusted EBITDA reconciliation to Net Income (Loss):Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,377 $(14,425) $ 103,878 $(13,725) $ 7,373Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 – – 461 –Total income tax provision (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,521 (9,925) 20,023 (6,952) 4,043Depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,596 10,743 12,127 22,578 10,931Accretion of asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155 137 92 158 107Full-cost ceiling impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 25,244 22,195 35,673 –Unrealized (gain) loss on derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,139) 2,375 (3,592) (1,534) (5,812)Stock option and grant expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 824 622 605 855 466Restricted stock grants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 34 60 36 25Net (gain)/loss on asset sales and inventory impairment . . . . . . . . . . . . . . . . . . . . . 224 379 (136,977) – –

Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $23,635 $ 15,184 $ 18,411 $ 37,550 $17,133


Nine MonthsEnded

September 30,

2010 2009 2008 2011 2010

(In thousands)Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by

Operating Activities:Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $27,273 $ 1,791 $ 25,851 $ 34,443 $21,390Net change in operating assets and liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,230) 15,717 (17,888) 2,692 (2,846)Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 – – 461 –Current income tax (benefit) provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,411) (2,324) 10,448 (46) (1,411)

Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $23,635 $ 15,184 $ 18,411 $ 37,550 $17,133

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Reserves Data

The following table presents summary data with respect to our estimated net proved oil and natural gasreserves at the dates indicated. The reserves estimates at December 31, 2008 presented in the table beloware based on evaluations prepared by our engineering staff, which have been audited by LaRoche PetroleumConsultants, Ltd., independent reservoir engineers. The reserves estimates at December 31, 2010 and 2009and at September 30, 2011 are based on evaluations prepared by our engineering staff, which have beenaudited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimateswere prepared in accordance with the Securities and Exchange Commission’s rules regarding oil and naturalgas reserves reporting that were in effect at the time of the preparation of the reserves report. Our totalestimated proved reserves are estimated using a conversion ratio of one Bbl per six Mcf.


2010 2009 2008 2011

Estimated proved reserves:(1) (2)

Natural gas (Bcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127.4 63.9 19.2 155.3Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152 103 131 1,083

Total (Bcfe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128.3 64.5 20.0 161.8Developed proved reserves (Bcfe) . . . . . . . . . . . . . . . . . . . . . . 44.1 26.0 20.0 55.8

Percent developed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34.3% 40.3% 100.0% 34.5%Undeveloped proved reserves (Bcfe) . . . . . . . . . . . . . . . . . . . . 84.3 38.6 – 106.0

PV-10 (in thousands)(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $119,869 $70,359 $44,069 $155,217Standardized Measure (in thousands)(4) . . . . . . . . . . . . . . . . . . . . . . $111,077 $65,061 $43,254 $143,372

(1) Numbers in table may not total due to rounding.

(2) Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, withoutgiving effect to derivative transactions, and were held constant throughout the life of the properties. The index prices were $41.00 perBbl for oil and $5.710 per MMBtu for natural gas at December 31, 2008. The unweighted arithmetic averages of thefirst-day-of-the-month prices for the 12 months ended December 31, 2009 were $57.65 per Bbl for oil and $3.866 per MMBtu for naturalgas, for the 12 months ended December 31, 2010 were $75.96 per Bbl for oil and $4.376 per MMBtu for natural gas, and for the12-month period from October 2010 to September 2011 were $91.00 per Bbl for oil and $4.158 per MMBtu for natural gas. These priceswere adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factorsaffecting the price received at the wellhead.

(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAPfinancial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fairmarket value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of provedreserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specifictax characteristics of such entities. Our PV-10 at December 31, 2008, 2009 and 2010 and at September 30, 2011 may be reconciled to ourStandardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxesassociated with such reserves. The discounted future income taxes at December 31, 2008, 2009 and 2010 and at September 30, 2011were, in thousands, $815, $5,298, $8,792 and $11,845, respectively.

(4) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated futuredevelopment, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timingof future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.

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Unaudited Operating Data

The following table sets forth summary unaudited production results for the company and itssubsidiaries for the years ended December 31, 2010, 2009 and 2008 and for the nine month periods endedSeptember 30, 2011 and 2010.


September 30,

2010 2009 2008 2011 2010

Production:Natural gas (Bcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4 4.8 3.1 10.9 5.9Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 30 37 113 24

Total natural gas equivalents (Bcfe)(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.6 5.0 3.3 11.6 6.0Average net daily production (MMcfe) . . . . . . . . . . . . . . . . . . . . . . . . . . 23.6 13.7 9.0 42.5 22.0

Average sales price (per Mcfe):Average sales price (including effects of hedging) . . . . . . . . . . . . . . . . . . . . . $4.58 $5.33 $8.86 $4.85 $4.68Average sales price (before effects of hedging) . . . . . . . . . . . . . . . . . . . . . . . . $3.96 $3.81 $9.27 $4.48 $4.19

Operating expenses (per Mcfe):Production taxes and marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $0.23 $0.22 $0.50 $0.41 $0.21Lease operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $0.61 $0.94 $1.41 $0.49 $0.63Depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1.81 $2.15 $3.67 $1.95 $1.82General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1.13 $1.42 $2.50 $0.81 $1.13

(1) Estimated using a conversion ratio of one Bbl per six Mcf.

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RISK FACTORS

You should carefully consider the risks described below before making an investment decision. Ourbusiness, financial condition or results of operations could be materially adversely affected by any of theserisks. The trading price of our common stock could decline due to any of these risks, and you may lose allor part of your investment.

Risks Related to the Oil and Natural Gas Industry and Our Business

Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and theSubstantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability toMeet Our Capital Expenditure Requirements and Financial Obligations.

The prices we receive for our oil and natural gas heavily influence our revenue, profitability, cash flowavailable for capital expenditures, access to capital and future rate of growth. Oil and natural gas arecommodities and, therefore, their prices are subject to wide fluctuations in response to relatively minorchanges in supply and demand. Historically, the markets for oil and natural gas have been volatile. Thesemarkets will likely continue to be volatile in the future. The prices we receive for our production, and thelevels of our production, depend on numerous factors. These factors include the following:

• the domestic and foreign supply of oil and natural gas;

• the domestic and foreign demand for oil and natural gas;

• the prices and availability of competitors’ supplies of oil and natural gas;

• the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlledoil companies relating to oil price and production controls;

• the price and quantity of foreign imports;

• the impact of U.S. dollar exchange rates on oil and natural gas prices;

• domestic and foreign governmental regulations and taxes;

• speculative trading of oil and natural gas futures contracts;

• the availability, proximity and capacity of gathering and transportation systems for natural gas;

• the availability of refining capacity;

• the prices and availability of alternative fuel sources;

• weather conditions and natural disasters;

• political conditions in or affecting oil and natural gas producing regions, including the Middle Eastand South America;

• the continued threat of terrorism and the impact of military action and civil unrest;

• public pressure on, and legislative and regulatory interest within, federal, state and localgovernments to stop, significantly limit or regulate hydraulic fracturing activities;

• the level of global oil and natural gas inventories and exploration and production activity;

• the impact of energy conservation efforts;

• technological advances affecting energy consumption; and

• overall worldwide economic conditions.

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Because we expect to produce more natural gas than oil in the immediate future, we will face more riskassociated with fluctuations in the price of natural gas than oil. Approximately 98% of our productionduring the year ended December 31, 2010, 94% of our production during the nine month period endedSeptember 30, 2011 and 96% of our proved reserves at September 30, 2011 are attributable to natural gas.In addition, three of our largest prospects, our Haynesville shale, Cotton Valley properties and our MeadePeak shale, currently produce or are expected to produce predominantly natural gas. As a result, they aresensitive to fluctuations in natural gas prices.

One of our current business strategies is to focus on increasing our oil and liquids production.Specifically, our near-term drilling opportunities in the Eagle Ford shale play focus on oil and liquids. Wecurrently intend to allocate approximately 84% of our 2012 capital expenditure budget to the exploration ofthe Eagle Ford shale. We believe that almost 85% of our Eagle Ford acreage is prospective predominantlyfor oil and liquids production, and we have identified 197 gross locations for potential future drilling in ourEagle Ford acreage. Therefore, our Eagle Ford shale play is highly susceptible to changes in oil prices.

Declines in oil or natural gas prices would not only reduce our revenue, but could reduce the amount ofoil and natural gas that we can produce economically. Should natural gas or oil prices decrease from currentlevels and remain there for an extended period of time, we may elect in the future to delay some of ourexploration and development plans for our prospects, or to cease exploration or development activities oncertain prospects due to the anticipated unfavorable economics from such activities, each of which wouldhave a material adverse effect on our business, financial condition, results of operations and reserves.

Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk,with Many Uncertainties That Could Adversely Affect Our Business.

Exploring for and developing hydrocarbon reserves involves a high degree of operational and financialrisk, which precludes us from definitively predicting the costs involved and time required to reach certainobjectives. Our drilling locations are in various stages of evaluation, ranging from a location that is ready todrill to a location that will require substantial additional interpretation before it can be drilled. The budgetedcosts of planning, drilling, completing and operating wells are often exceeded and such costs can increasesignificantly due to various complications that may arise during the drilling and operating processes.Before a well is spud, we may incur significant geological and geophysical (seismic) costs, which areincurred whether a well eventually produces commercial quantities of hydrocarbons, or is drilled at all.Exploration wells bear a much greater risk of loss than development wells. The analogies we draw fromavailable data from other wells, more fully explored locations or producing fields may not be applicable toour drilling locations. If our actual drilling and development costs are significantly more than our estimatedcosts, we may not be able to continue our operations as proposed and could be forced to modify our drillingplans accordingly.

If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gasreservoirs will be found or produced. We may drill or participate in new wells that are not productive. Wemay drill wells that are productive, but that do not produce sufficient net revenues to return a profit afterdrilling, operating and other costs. There is no way to predict in advance of drilling and testing whether anyparticular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling orcompletion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we maydamage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties

24

while drilling or completing the well, resulting in a reduction in production and reserves from the well orabandonment of the well. Whether a well is ultimately productive and profitable depends on a number ofadditional factors, including the following:

• general economic and industry conditions, including the prices received for oil and natural gas;

• shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, andqualified personnel;

• potential drainage by operators on adjacent properties;

• loss of or damage to oilfield development and service tools;

• problems with title to the underlying properties;

• increases in severance taxes;

• adverse weather conditions that delay drilling activities or cause producing wells to be shut down;

• domestic and foreign governmental regulations; and

• proximity to and capacity of transportation facilities.

If we do not drill productive and profitable wells in the future, our business, financial condition, resultsof operations, cash flows and reserves could be materially and adversely affected.

We May Have Accidents, Equipment Failures or Mechanical Problems While Drilling or Completing Wellsor in Production Activities, Which Could Adversely Affect Our Business.

While we are drilling and completing wells or involved in production activities, we may have accidentsor experience equipment failures or mechanical problems in a well that cause us to be unable to drill andcomplete the well or to continue to produce the well according to our plans. We may also damage apotentially hydrocarbon-bearing formation during drilling and completion operations. Such incidents mayresult in a reduction of our production and reserves from the well or in abandonment of the well.

Because Our Reserves and Production Are Concentrated in a Small Number of Properties, Problems inProduction and Markets Relating to Any Property Could Have a Material Impact on Our Business.

Almost all of our current oil and natural gas production and our proved reserves are attributable toproperties in north Louisiana and east Texas, and we expect that most of our operations in the near futurewill be primarily in south Texas. As a result, we may be disproportionately exposed to the impact of delaysor interruptions of production from these wells caused by transportation capacity constraints orinterruptions, curtailment of production, availability of equipment, facilities, personnel or services,significant governmental regulation, natural disasters, adverse weather conditions or plant closures forscheduled maintenance. In particular, our operations in south Texas may be adversely affected by hurricanesand tropical storms resulting in delays in exploration and drilling, damage to facilities and equipment andthe inability to receive equipment or to access personnel and products at affected job sites in a timelymanner. Due to the concentrated nature of our portfolio of properties, a number of our properties couldexperience any of the same conditions at the same time, resulting in a relatively greater impact on ourresults of operations than they might have on other companies that have a more diversified portfolio ofproperties. Such delays or interruptions could have a material adverse effect on our financial condition,results of operations and cash flows.

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Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline, WhichWould Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.

The rate of production from our oil and natural gas properties declines as our reserves are depleted.Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highlydependent on our success in: (i) efficiently developing and exploiting our current reserves on propertiesowned by us or by other persons or entities and (ii) economically finding or acquiring additional oil andnatural gas producing properties. In the future, we may have difficulty expanding our current production oracquiring new properties. During periods of low oil and/or natural gas prices, it will become more difficultto raise the capital necessary to finance expansion activities. If we are unable to replace our current andfuture production, our reserves will decrease, and our business, financial condition, results of operations andcash flows would be adversely affected.

Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil andNatural Gas We Will Receive, and Significant Inaccuracies in These Reserves Estimates or UnderlyingAssumptions Will Materially Affect the Quantities and Present Value of Our Reserves.

The process of estimating accumulations of oil and natural gas is complex and is not exact, due tonumerous inherent uncertainties. The process relies on interpretations of available geological, geophysical,engineering and production data. The extent, quality and reliability of this technical data can vary. Theprocess also requires certain economic assumptions related to, among other things, oil and natural gasprices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy ofa reserves estimate is a function of:

• the quality and quantity of available data;

• the interpretation of that data;

• the judgment of the persons preparing the estimate; and

• the accuracy of the assumptions.

The accuracy of any estimates of proved reserves generally increases with the length of the productionhistory. Due to the limited production history of many of our properties, the estimates of future productionassociated with these properties may be subject to greater variance to actual production than would be thecase with properties having a longer production history. As our wells produce over time and more data isavailable, the estimated proved reserves will be redetermined on at least an annual basis and may beadjusted to reflect new information based upon our actual production history, results of exploration anddevelopment, prevailing oil and natural gas prices and other factors.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operatingexpenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It ispossible that future production declines in our wells may be greater than we have estimated. Any significantvariance to our estimates could materially affect the quantities and present value of our reserves.

The Calculated Present Value of Future Net Revenues from Our Proven Reserves Will Not Necessarily Bethe Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves.

It should not be assumed that the present value of future net cash flows included in this prospectus is thecurrent market value of our estimated proved oil and natural gas reserves. We generally base the estimateddiscounted future net cash flows from proved reserves on current costs held constant over time without

26

escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month indexprices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actualfuture prices and costs may be materially higher or lower than the prices and costs used for these estimates andwill be affected by factors such as:

• actual prices we receive for oil and natural gas;

• actual cost and timing of development and production expenditures;

• the amount and timing of actual production; and

• changes in governmental regulations or taxation.

In addition, the 10% discount factor that is required to be used to calculate discounted future netrevenues for reporting purposes under GAAP is not necessarily the most appropriate discount factor basedon the cost of capital in effect from time to time and risks associated with our business and the oil andnatural gas industry in general.

Approximately 67% of Our Total Proved Reserves at September 30, 2011 Consisted of Undeveloped andDeveloped Non-Producing Reserves, and Those Reserves May Not Ultimately Be Developed or Produced.

At September 30, 2011, approximately 66% of our total proved reserves were undeveloped andapproximately 1% were developed non-producing. Our undeveloped and/or developed non-producingreserves may never be developed or produced, or such reserves may not be developed or produced withinthe time periods we have projected or, at the costs we have budgeted. Delays in the development of ourreserves or increases in costs to drill and develop such reserves would reduce the present value of ourestimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting insome projects becoming uneconomical. In addition, delays in the development of reserves or declines in oiland/or natural gas prices in the future could cause us to have to reclassify our proved reserves as unprovedreserves, which would materially affect our business, financial condition, results of operations and ability toraise capital.

Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures ThatMay Exceed Our Cash Flows From Operations and Potential Borrowings, and We May Be Unable toObtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth.

Our exploration and development activities are capital intensive. We make and expect to continue tomake substantial capital expenditures in our business for the development, exploitation, production andacquisition of oil and natural gas reserves. The net proceeds we receive from this offering, our operatingcash flows and future potential borrowings under our credit agreement or otherwise may not be adequate tofund our future acquisitions or future capital expenditure requirements. The rate of our future growth maybe dependent, at least in part, on our ability to access capital at rates and on terms we determine to beacceptable.

Our cash flows from operations and access to capital are subject to a number of variables, including:

• our estimated proved oil and natural gas reserves;

• the amount of oil and natural gas we produce from existing wells;

• the prices at which we sell our production;

• the costs of developing and producing our oil and natural gas reserves;

• our ability to acquire, locate and produce new reserves;

27

• the ability and willingness of banks to lend to us; and

• our ability to access the equity and debt capital markets.

In addition, future events, such as terrorist attacks, wars or combat peace-keeping missions, financialmarket disruptions, general economic recessions, oil and natural gas industry recessions, large companybankruptcies, accounting scandals, overstated reserves estimates by major public oil companies anddisruptions in the financial and capital markets have caused financial institutions, credit rating agencies andthe public to more closely review the financial statements, capital structures and earnings of publiccompanies, including energy companies. Such events have constrained the capital available to the energyindustry in the past, and such events or similar events could adversely affect our access to funding for ouroperations in the future.

If our revenues decrease as a result of lower oil and gas prices, operating difficulties, declines inreserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain ouroperations at current levels, further develop and exploit our current properties or invest in additionalexploration opportunities. Alternatively, a significant improvement in oil and gas prices could result in anincrease in our capital expenditures and we may be required to alter or increase our capitalizationsubstantially through the issuance of debt or equity securities, the sale of production payments, the sale ofnon-strategic assets, the borrowing of funds or otherwise to meet any increase in capital needs. If we areunable to raise additional capital from available sources at acceptable terms, our business, financialcondition and future results of operations could be adversely affected.

Our Operations Are Subject to Operational Hazards and Unforeseen Interruptions for Which We May NotBe Adequately Insured.

There are numerous operational hazards inherent in oil and natural gas exploration, development,production and gathering, including:

• unusual or unexpected geologic formations;

• natural disasters;

• adverse weather conditions;

• unanticipated pressures;

• loss of drilling fluid circulation;

• blowouts where oil or natural gas flows uncontrolled at a wellhead;

• cratering or collapse of the formation;

• pipe or cement leaks, failures or casing collapses;

• fires or explosions;

• releases of hazardous substances or other waste materials that cause environmental damage;

• pressures or irregularities in formations; and

• equipment failures or accidents;

In addition, there is an inherent risk of incurring significant environmental costs and liabilities in theperformance of our operations, some of which may be material, due to our handling of petroleumhydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of ourwastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices.

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Any of these or other similar occurrences could result in the disruption or impairment of our operations,substantial repair costs, personal injury or loss of human life, significant damage to property, environmentalpollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and otherfacilities near populated areas, including residential areas, commercial business centers and industrial sites,could significantly increase the level of damages resulting from these risks.

Insurance against all operational risks is not available to us. We are not fully insured against all risks,including development and completion risks that are generally not recoverable from third parties orinsurance. In addition, pollution and environmental risks generally are not fully insurable. Additionally, wemay elect not to obtain insurance if we believe that the cost of available insurance is excessive relative tothe perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or inamounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future atcommercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets dueto various factors may make it more difficult for us to obtain certain types of coverage in the future. As aresult, we may not be able to obtain the levels or types of insurance we would otherwise have obtained priorto these market changes, and the insurance coverage we do obtain may not cover certain hazards or allpotential losses that are currently covered, and may be subject to large deductibles. Losses and liabilitiesfrom uninsured and underinsured events and delay in the payment of insurance proceeds could have amaterial adverse effect on our business, financial condition, results of operations and cash flows.

The 2-D and 3-D Seismic Data and Other Advanced Technologies We Use Cannot Eliminate ExplorationRisk, Which Could Limit Our Ability to Replace and Grow Our Reserves and Materially and AdverselyAffect Our Future Cash Flows and Results of Operations.

We intend to employ visualization and 2-D and 3-D seismic images to assist us in exploration anddevelopment activities where applicable. These techniques only assist geoscientists in identifyingsubsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively ifhydrocarbons are present or economically producible. We could incur losses by drilling unproductive wellsbased on these technologies. Poor results from our exploration activities could limit our ability to replaceand grow reserves and materially and adversely affect our future cash flows and results of operations.

We Currently Own Only a Limited Amount of Seismic and Other Geological Data and May Have DifficultyObtaining Additional Data at a Reasonable Cost, Which Could Adversely Affect Our Future Cash Flowsand Results of Operations.

We currently own only a limited amount of seismic and other geological data to assist us in explorationand development activities. We intend to obtain access to additional data in our areas of interest throughlicensing arrangements with companies that own or have access to that data or by paying to obtain that datadirectly. Seismic and geological data can be expensive to license or obtain. We may not be able to license orobtain such data at an acceptable cost.

The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies andPersonnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Abilityto Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, WhichCould Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.

Shortages or the high cost of drilling rigs, completion equipment and services, supplies or personnelcould delay or adversely affect our operations. When drilling activity in the United States increases,associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies

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and personnel and the services and products of other vendors to the industry. These costs may increase, andnecessary equipment and services may become unavailable to us at economical prices. Should this increasein costs occur, we may delay drilling activities, which may limit our ability to establish and replace reserves,or we may incur these higher costs, which may negatively affect our financial condition, results ofoperations and cash flows.

In addition, the demand for hydraulic fracturing services currently exceeds the availability of fracturingequipment and crews across the industry and in our operating areas in particular. The accelerated wear andtear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fieldscharacterized by longer lateral lengths and larger numbers of fracturing stages has further amplified thisequipment and crew shortage. If demand for fracturing services continues to increase or the supply offracturing equipment and crews decreases, then higher costs could result and could adversely affect ourbusiness and results of operations.

Our Identified Drilling Locations Are Scheduled Out over Several Years, Making Them Susceptible toUncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.

Our management team has identified and scheduled drilling locations in our operating areas over amulti-year period. Our ability to drill and develop these locations depends on a number of factors, includingthe availability of equipment and capital, approval by regulators, seasonal conditions, oil and natural gasprices, assessment of risks, costs and drilling results. The final determination on whether to drill any ofthese locations will be dependent upon the factors described elsewhere in this prospectus as well as, to somedegree, the results of our drilling activities with respect to our established drilling locations. Because ofthese uncertainties, we do not know if the drilling locations we have identified will be drilled within ourexpected timeframe or at all or if we will be able to economically produce hydrocarbons from these or anyother potential drilling locations. Our actual drilling activities may be materially different from our currentexpectations, which could adversely affect our financial condition, results of operations and cash flows.

We Have Limited Control over Activities on Properties We Do Not Operate.

We are not the operator on some of our properties, particularly in the Haynesville shale. As a result ofour sale of certain assets to a subsidiary of Chesapeake Energy Corporation in 2008, we do not operate oneof our most significant natural gas assets in the Haynesville shale. We also acquired other non-operatedacreage positions in north Louisiana. Because we are not the operator for these properties, our ability toexercise influence over the operations of these properties or their associated costs is limited. Ourdependence on the operators and other working interest owners of these projects and our limited ability toinfluence operations and associated costs or control the risks could materially and adversely affect therealization of our targeted returns on capital in drilling or acquisition activities. The success and timing ofour drilling and development activities on properties operated by others therefore depends upon a number offactors, including:

• timing and amount of capital expenditures;

• the operator’s expertise and financial resources;

• the rate of production of reserves, if any;

• approval of other participants in drilling wells; and

• selection of technology.

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In areas where we do not have the right to propose the drilling of wells, we may have limited influence onwhen, how and at what pace our properties in those areas are developed. Further, the operators of thoseproperties may experience financial problems in the future or may sell their rights to another operator not of ourchoosing, both of which could limit our ability to develop and monetize the underlying natural gas reserves.

A Component of Our Growth May Come Through Acquisitions, and Our Failure to Identify or CompleteFuture Acquisitions Successfully Could Reduce Our Earnings and Hamper Our Growth.

We may be unable to identify properties for acquisition or to make acquisitions on terms that weconsider economically acceptable. There is intense competition for acquisition opportunities in our industry.Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.The completion and pursuit of acquisitions may be dependent upon, among other things, our ability toobtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow throughacquisitions will require us to continue to invest in operations, financial and management informationsystems and to attract, retain, motivate and effectively manage our employees. The inability to manage theintegration of acquisitions effectively could reduce our focus on subsequent acquisitions and currentoperations, and could negatively impact our results of operations and growth potential. Our financialposition, results of operations and cash flows may fluctuate significantly from period to period, as a result ofthe completion of significant acquisitions during particular periods. If we are not successful in identifying oracquiring any material property interests, our earnings could be reduced and our growth could be restricted.

We may engage in bidding and negotiating to complete successful acquisitions. We may be required toalter or increase substantially our capitalization to finance these acquisitions through the use of cash onhand, the issuance of debt or equity securities, the sale of production payments, the sale of non-strategicassets, the borrowing of funds or otherwise. Our credit agreement includes covenants limiting our ability toincur additional debt. If we were to proceed with one or more acquisitions involving the issuance of ourcommon stock, our shareholders would suffer dilution of their interests. Furthermore, our decision toacquire properties that are substantially different in operating or geologic characteristics or geographiclocations from areas with which our staff is familiar may impact our productivity in such areas.

We May Purchase Oil and Natural Gas Properties with Liabilities or Risks That We Did Not Know Aboutor That We Did Not Assess Correctly, and, as a Result, We Could Be Subject to Liabilities That CouldAdversely Affect Our Results of Operations.

Before acquiring oil and natural gas properties, we estimate the reserves, future oil and natural gasprices, operating costs, potential environmental liabilities and other factors relating to the properties.However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain.As a result, we may not discover all existing or potential problems associated with the properties we buy.We may not become sufficiently familiar with the properties to assess fully their deficiencies andcapabilities. We do not generally perform inspections on every well or property, and we may not be able toobserve mechanical and environmental problems even when we conduct an inspection. The seller may notbe willing or financially able to give us contractual protection against any identified problems, and we maydecide to assume environmental and other liabilities in connection with properties we acquire. If we acquireproperties with risks or liabilities we did not know about or that we did not assess correctly, our financialcondition, results of operations and cash flows could be adversely affected as we settle claims and incurcleanup costs related to these liabilities.

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Strategic Relationships Upon Which We May Rely Are Subject to Change, Which May Diminish Our Abilityto Conduct Our Operations.

Our ability to explore, develop and produce oil and natural gas resources successfully and acquire oil andnatural gas interests and acreage depends on our developing and maintaining close working relationships withindustry participants and on our ability to select and evaluate suitable acquisition opportunities in a highlycompetitive environment. These realities are subject to change and may impair our ability to grow.

To develop our business, we will endeavor to use the business relationships of our management, boardand special board advisors to enter into strategic relationships, which may take the form of contractualarrangements with other oil and natural gas companies, including those that supply equipment and otherresources that we expect to use in our business. We may not be able to establish these strategicrelationships, or if established, we may not be able to maintain them. In addition, the dynamics of ourrelationships with strategic partners may require us to incur expenses or undertake activities we would nototherwise be inclined to incur in order to fulfill our obligations to these partners or maintain ourrelationships. If our strategic relationships are not established or maintained, our business prospects may belimited, which could diminish our ability to conduct our operations.

The Marketability of Our Production Is Dependent Upon Oil and Natural Gas Gathering andTransportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oiland Natural Gas Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.

The unavailability of satisfactory oil and natural gas transportation arrangements may hinder ouraccess to oil and natural gas markets or delay production from our wells. The availability of a ready marketfor our oil and natural gas production depends on a number of factors, including the demand for, and supplyof, oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to marketour production depends in substantial part on the availability and capacity of gathering systems, pipelinesand processing facilities owned and operated by third parties. Our failure to obtain these services onacceptable terms could materially harm our business. We may be required to shut-in wells for lack of amarket or because of inadequacy or unavailability of pipeline or gathering system capacity. If that were tooccur, we would be unable to realize revenue from those wells until production arrangements were made todeliver our production to market. Furthermore, if we were required to shut-in wells we might also beobligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases.

The disruption of third party facilities due to maintenance and/or weather could negatively impact ourability to market and deliver our products. The third parties control when or if such facilities are restoredand what prices will be charged. We generally do not purchase firm transportation on third party facilities,and, therefore, our production transportation can be interrupted by those having firm arrangements. Federaland state regulation of oil and natural gas production and transportation, tax and energy policies, changes insupply and demand, pipeline pressures, damage to or destruction of pipelines and general economicconditions could adversely affect our ability to produce, gather and transport oil and natural gas.

Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in FinancialLosses.

To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, usingprimarily “costless collars,” with respect to a portion of our future production. A costless collar provides uswith downside price protection through the purchase of a put option which is financed through the sale of acall option. Because the call option proceeds are used to offset the cost of the put option, this arrangement is

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initially “costless” to us. The goal of these and other hedges is to lock in a range of prices so as to mitigateprice volatility and increase the predictability of cash flows. These transactions limit our potential gains ifoil or natural gas prices rise above the maximum price established by the call option and may offerprotection if prices fall below the minimum price established by the put option only to the extent of thevolumes then hedged.

In addition, hedging transactions may expose us to the risk of financial loss in certain othercircumstances, including instances in which our production is less than expected or the counterparties to ourput and call option contracts fail to perform under the contracts.

Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, whichcould impair its ability to perform under the terms of the contracts. We are unable to predict sudden changesin a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accuratelypredict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions.

Furthermore, there may be times when we have not hedged our production when, in retrospect, itwould have been advisable to do so. Decisions as to whether and what production volumes to hedge aredifficult and depend on market conditions and our forecast of future production and oil and gas prices, andwe may not always employ the optimal hedging strategy. We may employ hedging strategies in the futurethat differ from those that we have used in the past, and neither the continued application of our currentstrategies nor our use of different hedging strategies may be successful. Our existing oil and natural gashedges will expire at various times during 2012 and 2013.

An Increase in the Differential Between the NYMEX or other Benchmark Prices of Oil and Natural Gas andthe Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, FinancialCondition, Results of Operations and Cash Flows.

The prices that we receive for our oil and natural gas production sometimes reflect a discount to therelevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The differencebetween the benchmark price and the prices we receive is called a differential. Increases in the differentialbetween the benchmark prices for oil and natural gas and the wellhead price we receive could adverselyaffect our business, financial condition, results of operations and cash flows. We do not have, and may nothave in the future, any derivative contracts covering the amount of the basis differentials we experience inrespect of our production. As such, we will be exposed to any increase in such differentials.

We Are Subject to Government Regulation and Liability, including Complex Environmental Laws, WhichCould Require Significant Expenditures.

The exploration, development, production and sale of oil and natural gas in the United States aresubject to many federal, state and local laws, rules and regulations, including complex environmental lawsand regulations. Matters subject to regulation include discharge permits, drilling bonds, reports concerningoperations, the spacing of wells, unitization and pooling of properties, taxation or environmental mattersand health and safety criteria addressing worker protection. Under these laws and regulations, we may berequired to make large expenditures that could materially adversely affect our financial condition, results ofoperations and cash flows. These expenditures could include payments for:

• personal injuries;

• property damage;

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• containment and clean up of oil and other spills;

• the management and disposal of hazardous materials;

• remediation and clean-up costs; and

• other environmental damages.

We do not believe that full insurance coverage for all potential damages is available at a reasonablecost. Failure to comply with these laws and regulations also may result in the suspension or terminationof our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or theimposition of investigatory or other remedial obligations. Laws, rules and regulations protecting theenvironment have changed frequently and the changes often include increasingly stringent requirements.These laws, rules and regulations may impose liability on us for environmental damage and disposal ofhazardous materials even if we were not negligent or at fault. We may also be found to be liable for theconduct of others or for acts that complied with applicable laws, rules or regulations at the time weperformed those acts. These laws, rules and regulations are interpreted and enforced by numerous federaland state agencies. In addition, private parties, including the owners of properties upon which our wellsare drilled or the owners of properties adjacent to or in close proximity to those properties, may alsopursue legal actions against us based on alleged non-compliance with certain of these laws, rules andregulations.

We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or HaveEliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oiland Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which CouldAdversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.

The federal, state and local governments in the areas in which we operate impose taxes on the oil andnatural gas products we sell and, for many of our wells, sales and use taxes on significant portions of ourdrilling and operating costs. In the past, there has been a significant amount of discussion by legislators andpresidential administrations concerning a variety of energy tax proposals. Many states have raised statetaxes on energy sources, and additional increases may occur. Changes to tax laws that are applicable to uscould adversely affect our business and our financial results.

Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferencescurrently available to oil and natural gas exploration and production companies. Such changes include, butare not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties,(ii) the elimination of current deductions for intangible drilling and development costs, (iii) the eliminationof the deduction for certain United States production activities and (iv) the increase in the amortizationperiod for geological and geophysical costs paid or incurred in connection with the exploration for, ordevelopment of, oil or natural gas within the United States. These changes were included in the WhiteHouse budget proposals, released on February 26, 2009, February 1, 2010 and February 14, 2011, and maybe raised again in the future. The American Jobs Act of 2011 proposed by President Obama also containssimilar changes. It is unclear whether any such changes will actually be enacted or, if enacted, how soonany such changes could become effective. The passage of any legislation as a result of the budget proposalsor any other similar change in U.S. federal income tax law could affect certain tax deductions that arecurrently available with respect to oil and natural gas exploration and production activities and couldnegatively impact our financial condition, results of operations and cash flows.

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We May Be Required to Write Down the Carrying Value of Our Proved Properties Under Accounting Rulesand these Write-Downs Could Adversely Affect Our Financial Condition.

There is a risk that we will be required to write down the carrying value of our oil and natural gasproperties when oil or natural gas prices are low. In addition, non-cash write-downs may occur if we have:

• downward adjustments to our estimated proved reserves;

• increases in our estimates of development costs; or

• deterioration in our exploration results.

We periodically review the carrying value of our oil and natural gas properties under full-costaccounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less relateddeferred income taxes may not exceed a cost center ceiling that is based on the present value, based onconstant prices and costs projected forward from a single point in time, of estimated future after-tax net cashflows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gasproperties less related deferred income taxes exceed the cost center ceiling, we must charge the amount ofthis excess to operations in the period in which the excess occurs. We may not reverse write-downs even ifprices increase in subsequent periods. A write-down does not affect net cash flows from operating activities,but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity andcould lower the value of our common stock.

We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.

If an examination of the title history of a property that we have purchased reveals an oil and natural gaslease has been purchased in error from a person who is not the owner of the mineral interest desired, ourinterest would be worthless. In such an instance, the amount paid for such oil and natural gas lease as wellas any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would belost.

It is our practice, in acquiring oil and natural gas leases, or undivided interests in oil and natural gasleases, not to undergo the expense of retaining lawyers to examine the title to the mineral interest to beplaced under lease or already placed under lease. Rather, we will rely upon the judgment of oil and naturalgas lease brokers and/or landmen who perform the field work in examining records in the appropriategovernmental office before attempting to acquire a lease on a specific mineral interest.

Prior to the drilling of an oil and natural gas well, however, it is the normal practice in the oil andnatural gas industry for the person or company acting as the operator of the well to obtain a preliminary titlereview of the spacing unit within which the proposed oil and natural gas well is to be drilled to ensure thereare no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curativework must be done to correct deficiencies in the marketability of the title, and such curative work entailsexpense. Our failure to cure any title defects may adversely impact our ability in the future to increaseproduction and reserves. In the future, we may suffer a monetary loss from title defects or title failure.Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. Ifthere are any title defects or defects in assignment of leasehold rights in properties in which we hold aninterest, we will suffer a financial loss which could adversely affect our financial condition, results ofoperations and cash flows.

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The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to HedgeRisks Associated with Our Business.

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and ConsumerProtection Act, or the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S.financial system. The Dodd-Frank Act, among other things, sets forth the new framework for regulatingcertain derivative products including the commodity hedges of the type used by us, but many aspects of thislaw are subject to further rulemaking and will take effect over several years. As a result, it is difficult toanticipate the overall impact of the Dodd-Frank Act on our ability or willingness to continue entering intoand maintaining such commodity hedges and the terms thereof. Based upon the limited assessments we areable to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act couldhave a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. Inparticular, the Dodd-Frank Act could result in the implementation of position limits and additionalregulatory requirements on our derivative arrangements, which could include new margin, reporting andclearing requirements. In addition, this legislation could have a substantial impact on our counterparties andmay increase the cost of our derivative arrangements in the future.

If these types of commodity hedges become unavailable or uneconomic, our commodity price riskcould increase, which would increase the volatility of revenues and may decrease the amount of creditavailable to us. Any limitations or changes in our use of derivative arrangements could also materially affectour future ability to conduct acquisitions.

Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result inIncreased Costs and Additional Operating Restrictions or Delays.

Congress has considered, but has not yet passed, legislation to amend the federal Safe Drinking WaterAct to remove the exemption from restrictions on underground injection of fluids near drinking watersources granted to hydraulic fracturing operations and require reporting and disclosure of chemicals used byoil and natural gas companies in the hydraulic fracturing process. Hydraulic fracturing involves the injectionof water, sand or other propping agents and chemicals under pressure into rock formations to stimulatenatural gas production. We routinely use hydraulic fracturing to produce commercial quantities of oil,liquids and natural gas from shale formations such as the Haynesville and the Eagle Ford shales, where wefocus our operations. Sponsors of bills before the Senate and House of Representatives have asserted thatchemicals used in the fracturing process could adversely affect drinking water supplies. Such legislation, ifadopted, could increase the possibility of litigation and establish an additional level of regulation at thefederal level that could lead to operational delays or increased operating costs and could, and in alllikelihood would, result in additional regulatory burdens, making it more difficult to perform hydraulicfracturing operations and increasing our costs of compliance. Moreover, the U.S. Environmental ProtectionAgency, or EPA, is conducting a comprehensive research study on the potential adverse impacts thathydraulic fracturing may have on drinking water and groundwater. In addition, in December 2011, the EPApublished an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution of anatural gas field in Wyoming, although this study remains subject to review and public comments.Consequently, even if federal legislation is not adopted soon or at all, the performance of the hydraulicfracturing study by the EPA could spur further action at a later date towards federal legislation andregulation of hydraulic fracturing or similar production operations.

In addition, a number of states are considering or have implemented more stringent regulatoryrequirements applicable to fracturing, which could include a moratorium on drilling and effectively prohibitfurther production of natural gas through the use of hydraulic fracturing or similar operations. For example,

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Texas has adopted legislation that requires the disclosure of information regarding the substances used inthe hydraulic fracturing process to the Railroad Commission of Texas and the public. This legislation andany implementing regulation could increase our costs of compliance and doing business.

The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting, thehydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shaleformations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federallegislation or regulatory initiatives by the EPA, fracturing activities could become subject to additionalpermitting requirements, and also to attendant permitting delays and potential increases in cost, which couldadversely affect our business and results of operations.

Legislation or Regulations Restricting Emissions of “Greenhouse Gases” Could Result in IncreasedOperating Costs and Reduced Demand for the Natural Gas, Natural Gas Liquids and Oil We ProduceWhile the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to IncurSignificant Costs in Preparing for or Responding to those Effects.

On December 15, 2009, the EPA published its final findings that emissions of carbon dioxide, methaneand other “greenhouse gases” present an endangerment to public health and welfare because emissions ofsuch gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and otherclimatic changes. These findings allow the EPA to adopt and implement regulations that would restrictemissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPAhas adopted regulations that would require a reduction in emissions of greenhouse gases from motorvehicles and permitting and presumably requiring a reduction in greenhouse gas emissions from certainstationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reportingof greenhouse gas emissions from specified large greenhouse gas emission sources in the United Statesbeginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a final rulethat expands its rule on reporting of greenhouse gas emissions to include owners and operators of petroleumand natural gas systems. Monitoring of those newly covered emissions commenced on January 1, 2011,with the first annual reports due to the EPA on March 31, 2012. The adoption and implementation of anyregulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, ourequipment and operations could require us to incur costs to reduce emissions of greenhouse gases associatedwith our operations. There were attempts at comprehensive legislation establishing a cap and trade program,but that legislation appears unlikely to pass. Further, various states have adopted legislation that seeks tocontrol or reduce emissions of greenhouse gases from a wide range of sources. Any such legislation couldadversely affect demand for the natural gas, oil and liquids that we produce.

A Change in the Jurisdictional Characterization of Some of Our Assets by FERC or a Change in Policy byIt May Result in Increased Regulation of Our Assets, Which May Cause Our Revenues to Decline andOperating Expenses to Increase.

Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities fromregulation by the Federal Energy Regulatory Commission, or FERC, as a natural gas company under theNGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC hasused to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However,the distinction between FERC-regulated transmission services and federally unregulated gathering services isthe subject of on-going litigation, so the classification and regulation of our gathering facilities are subject tochange based on future determinations by FERC, the courts or Congress. A change in the jurisdictionalcharacterization by FERC or Congress or a change in policy by either of them may result in increasedregulation of our assets, which may cause our revenues to decline and operating expenses to increase.

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Should We Fail to Comply with All Applicable FERC-Administered Statutes, Rules, Regulations andOrders, We Could Be Subject to Substantial Penalties and Fines.

Under the Domenici-Barton Energy Policy Act of 2005, FERC has civil penalty authority under theNGA to impose penalties for current violations of up to $1.0 million per day for each violation anddisgorgement of profits associated with any violation. Our systems have not yet been regulated by FERC, asa natural gas company subject to the provisions of the NGA. FERC has adopted regulations that maysubject certain of our otherwise non-FERC/NGA jurisdictional facilities to FERC annual reporting and dailyscheduled flow and capacity posting requirements. Additional laws, rules and regulations pertaining to thoseand other matters may be considered or adopted by FERC or Congress from time to time. Failure to complywith those laws, rules and regulations in the future could subject us to civil penalty liability.

Competition in the Oil and Natural Gas Industry is Intense Making It More Difficult for Us to AcquireProperties, Market Natural Gas and Secure Trained Personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend onour ability to evaluate and select suitable properties and to consummate transactions in a highly competitiveenvironment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also,there is substantial competition for capital available for investment in the oil and natural gas industry. Manyof our competitors possess and employ financial, technical and personnel resources substantially greaterthan ours. Those companies may be able to pay more for productive oil and natural gas properties andexploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospectsthan our financial or personnel resources permit. In addition, other companies may be able to offer bettercompensation packages to attract and retain qualified personnel than we are able to offer. The cost to attractand retain qualified personnel has increased in recent years due to competition and may increasesubstantially in the future. We may not be able to compete successfully in the future in acquiringprospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining qualitypersonnel and raising additional capital, which could have a material adverse effect on our business.

Our Competitors May Use Superior Technology and Data Resources that We May Be Unable to Afford orThat Would Require a Costly Investment by Us in Order to Compete with Them More Effectively.

Our industry is subject to rapid and significant advancements in technology, including the introductionof new products and services using new technologies and databases. As our competitors use or develop newtechnologies, we may be placed at a competitive disadvantage, and competitive pressures may force us toimplement new technologies at a substantial cost. In addition, many of our competitors will have greaterfinancial, technical and personnel resources that allow them to enjoy technological advantages and may inthe future allow them to implement new technologies before we can. We cannot be certain that we will beable to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of thetechnologies that we will use or that we may implement in the future may become obsolete, and we may beadversely affected.

Certain of Our Unproved and Unevaluated Acreage Is Subject to Leases that Will Expire Over the NextSeveral Years Unless Production Is Established on Units Containing the Acreage.

At September 30, 2011, we had leasehold interests in approximately 122,000 net acres across all of ourareas of interest that are not currently held by production and are subject to leases with primary or renewedterms that expire prior to December 31, 2013. Unless we establish production in paying quantities on unitscontaining these leases during their terms or we renew such leases, these leases will expire. If our leases

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expire, we will lose our right to develop the related properties. The cost to renew such leases may increasesignificantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Inaddition, on certain portions of our acreage, third party leases may have been taken and could becomeimmediately effective if our leases expire. As such, our actual drilling activities may materially differ from ourcurrent expectations, which could adversely affect our business, financial condition, results of operations andcash flows.

We May Have Difficulty Managing Growth in Our Business, Which Could Have a Material Adverse Effecton Our Business, Financial Condition, Results of Operations and Cash Flows and Our Ability to ExecuteOur Business Plan in a Timely Fashion.

Because of our small size, growth in accordance with our business plans, if achieved, will place asignificant strain on our financial, technical, operational and management resources. As we expand ouractivities, including our planned increase in oil exploration, development and production, and increase thenumber of projects we are evaluating or in which we participate, there will be additional demands on ourfinancial, technical and management resources. The failure to continue to upgrade our technical,administrative, operating and financial control systems or the occurrence of unexpected expansiondifficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleumengineers and landmen could have a material adverse effect on our business, financial condition, results ofoperations and cash flows and our ability to execute our business plan in a timely fashion.

Financial Difficulties Encountered by Our Oil and Natural Gas Purchasers, Third Party Operators orOther Third Parties Could Decrease Our Cash Flow from Operations and Adversely Affect the Explorationand Development of Our Prospects and Assets.

We derive essentially all of our revenues from the sale of our oil and natural gas to unaffiliated thirdparty purchasers, independent marketing companies and mid-stream companies. Any delays in paymentsfrom our purchasers caused by financial problems encountered by them will have an immediate negativeeffect on our results of operations and cash flows.

Liquidity and cash flow problems encountered by our working interest co-owners or the third partyoperators of our non-operated properties may prevent or delay the drilling of a well or the development of aproject. Our working interest co-owners may be unwilling or unable to pay their share of the costs ofprojects as they become due. In the case of a farmout party, we would have to find a new farmout party orobtain alternative funding in order to complete the exploration and development of the prospects subject to afarmout agreement. In the case of a working interest owner, we could be required to pay the workinginterest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capitalnecessary to fund either of these contingencies or that we would be able to find a new farmout party.

We May Incur Indebtedness Which Could Reduce Our Financial Flexibility, Increase Interest Expense andAdversely Impact Our Operations and Our Unit Costs.

Upon the completion of this offering and the application of the net proceeds to be received by us, weexpect to have available borrowings of approximately $98.7 million under our credit agreement (aftergiving effect to outstanding letters of credit). Our borrowing base under our credit agreementimmediately following the offering will be limited to $100 million. Our borrowing base is determinedsemi-annually by our lenders based primarily on the estimated value of our existing and future acquiredoil and gas reserves. Our credit agreement is secured by substantially all of our interests in our oil and gasproperties and other assets and contains covenants restricting our ability to incur additional indebtedness,

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which may limit our ability to obtain additional financing. In addition, the borrowing base under ourcredit agreement is subject to periodic redeterminations, and we could be forced to repay a portion of ourborrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not havesufficient funds to make such repayments.

At January 27, 2012, all borrowings under our credit agreement bore interest at a variable rate of3.25% plus a Eurodollar-based rate per annum, which equated to approximately 3.5% per annum. In thefuture, we may incur significant amounts of additional indebtedness, including under our credit agreement,in order to make acquisitions or to develop our properties. Interest rates on such future indebtedness may behigher than current levels, causing our financing costs to increase accordingly.

Our level of indebtedness could affect our operations in several ways, including the following:

• a significant portion of our cash flows could be used to service our indebtedness;

• a high level of debt would increase our vulnerability to general adverse economic and industryconditions;

• any covenants contained in the agreements governing our outstanding indebtedness could limit ourability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

• a high level of debt may place us at a competitive disadvantage compared to our competitors thatare less leveraged and, therefore, may be able to take advantage of opportunities that ourindebtedness may prevent us from pursuing;

• our debt covenants may also affect our flexibility in planning for, and reacting to, changes in theeconomy and in our industry; and

• a high level of debt may impair our ability to obtain additional financing in the future for workingcapital, capital expenditures, acquisitions and general corporate or other purposes.

A high level of indebtedness increases the risk that we may default on our debt obligations. Our abilityto meet our debt obligations and to reduce our level of indebtedness depends on our future performance.General economic conditions, oil and natural gas prices and financial, business and other factors affect ouroperations and our future performance. We may not be able to generate sufficient cash flows to pay theprincipal or interest on our debt, and future working capital, borrowings or equity financing may not beavailable to pay or refinance such debt. Factors that will affect our ability to raise cash through an offeringof our capital stock or a refinancing of our debt include financial market conditions, the value of our assetsand our performance at the time we need capital. If we do not have sufficient funds and are otherwiseunable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significantassets or have a portion of our assets foreclosed upon which could have a material adverse effect on ourbusiness and financial results.

Our Success Depends, to a Large Extent, on Our Ability to Retain Our Key Personnel, Including OurChairman of the Board, Chief Executive Officer and President, the Members of Our Board of Directors andOur Special Board Advisors, and the Loss of Any Key Personnel, Board Member or Special Board AdvisorCould Disrupt Our Business Operations.

Investors in our common stock must rely upon the ability, expertise, judgment and discretion of ourmanagement and the success of our technical team in identifying, evaluating and developing prospects andreserves. Our performance and success are dependent to a large extent on the efforts and continued

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employment of our management and technical personnel, including our Chairman, President and ChiefExecutive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnelof equal experience and capabilities, and their successors may not be as effective. We have entered intoemployment agreements with Mr. Foran and other key personnel. However, these employment agreementsdo not ensure that these individuals remain in our employment. If Mr. Foran or any of these other keypersonnel resign or become unable to continue in their present roles and if they are not adequately replaced,our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain,nor do we plan to obtain, any insurance against the loss of any of these individuals.

We have an active board of directors that meets several times throughout the year and is intimatelyinvolved in our business and the determination of our operational strategies. Members of our board ofdirectors work closely with management to identify potential prospects, acquisitions and areas for furtherdevelopment. Many of our directors have been involved with us since our inception and have a deepunderstanding of our operations and culture. If any of our directors resign or become unable to continue intheir present role, it may be difficult to find replacements with the same knowledge and experience and as aresult, our operations may be adversely affected.

In addition, our board consults regularly with our special advisors regarding our business and theevaluation, exploration, engineering and development of our prospects. Due to the knowledge andexperience of our special advisors, they play a key role in our multi-disciplined approach to makingdecisions regarding prospects, acquisitions and development. If any of our special advisors resign orbecome unable to continue in their present role, our operations may be adversely affected.

Our Management Team Will Own Approximately 12.7% of Our Common Stock after the Consummation ofthis Offering, Which Could Give Them Influence in Corporate Transactions and Other Matters, and theInterests of Our Management Could Differ From Yours.

Our directors and officers will beneficially own approximately 12.7% of our outstanding shares ofcommon stock following this offering based on a total of 54,719,860 shares of common stock outstandingupon consummation of this offering. These shareholders will be positioned to influence or control to somedegree the outcome of matters requiring a shareholder vote, including the election of directors, the adoptionof any amendment to our certificate of formation or bylaws and the approval of mergers and othersignificant corporate transactions. Their influence or control of the company may have the effect of delayingor preventing a change of control of the company and may adversely affect the voting and other rights ofother shareholders. In addition, due to their ownership interest in our common stock, they may be able toremain entrenched in their positions.

Risks Relating to this Offering and Our Common Stock

The Market Price and Trading Volume of Our Common Stock May Be Volatile Following this Offering.

The market price of our common stock could vary significantly as a result of a number of factors. Inaddition, the trading volume of our common stock may fluctuate and cause significant price variations tooccur. In the event of a drop in the market price of our common stock, you could lose a substantial part orall of your investment in our common stock. Factors that could affect our stock price or result influctuations in the market price or trading volume of our common stock include:

• our actual or anticipated operating and financial performance and drilling locations, includingreserves estimates;

• quarterly variations in the rate of growth of our financial indicators, such as net income per share,net income and cash flows, or those of companies that are perceived to be similar to us;

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• changes in revenue, cash flows or earnings estimates or publication of reports by equity researchanalysts;

• speculation in the press or investment community;

• public reaction to our press releases, announcements and filings with the Securities and ExchangeCommission, or SEC;

• sales of our common stock by us, the selling shareholders or other shareholders, or the perceptionthat such sales may occur;

• general financial market conditions and oil and gas industry market conditions, includingfluctuations in commodity prices;

• the realization of any of the risk factors presented in this prospectus;

• the recruitment or departure of key personnel;

• commencement of or involvement in litigation;

• the prices of oil and natural gas;

• the success of our exploration and development operations, and the marketing of any oil andnatural gas we produce;

• changes in market valuations of companies similar to ours; and

• domestic and international economic, legal and regulatory factors unrelated to our performance.

The stock markets in general have experienced extreme volatility that has often been unrelated to theoperating performance of particular companies. These broad market fluctuations may adversely affect thetrading price of our common stock.

There Is Currently No Public Market for Our Common Stock, and an Active Liquid Trading Market for OurCommon Stock May Not Develop Following this Offering.

Prior to this offering, there has been no public market for our common stock. Our common stock hasbeen approved for listing on the New York Stock Exchange, or NYSE. Liquid and active trading marketsusually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders.Our common stock may have limited trading volume, and many investors may not be interested in owningour common stock because of the inability to acquire or sell a substantial block of our common stock at onetime. Such illiquidity could have an adverse effect on the market price of our common stock. In addition, ashareholder may not be able to borrow funds using our common stock as collateral because lenders may beunwilling to accept the pledge of securities having such a limited market. We cannot assure you that anactive trading market for our common stock will develop or, if one develops, be sustained.

The Initial Public Offering Price of Our Common Stock May Not Be Indicative of the Market Price of OurCommon Stock after this Offering.

The initial public offering price may not necessarily bear any relationship to our book value or the fairmarket value of our assets. The initial public offering price has been negotiated between us andrepresentatives of the underwriters, based on numerous factors which we discuss in the “Underwriters”section of this prospectus, and may not be indicative of the market price of our common stock after thisoffering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greaterthan the price paid by you in this offering.

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Purchasers of Common Stock in this Offering will Experience Immediate and Substantial Dilution of$4.71 Per Share.

Based on the initial public offering price of $12.00 per share, purchasers of our common stock in thisoffering will experience an immediate and substantial dilution of $4.71 per share in the pro forma as adjustednet tangible book value per share of common stock from the initial public offering price, and our pro forma asadjusted net tangible book value at September 30, 2011 after giving effect to this offering would be $7.29 pershare. See “Dilution” for a complete description of the calculation of net tangible book value.

Our Intended Use of the Net Proceeds We Receive from this Offering is as Set Forth Under “Use ofProceeds” in this Prospectus, but Our Budgets May Change Throughout 2012 Depending on Oil andNatural Gas Prices, the Outcome of Our Drilling and Exploration Programs and Proposed Acquisitions.

As we discuss in the “Use of Proceeds” section in this prospectus, we intend to use the net proceeds wereceive from this offering and from any exercise of the underwriters’ over-allotment option to repay the thenoutstanding borrowings under our credit agreement and to fund a portion of our anticipated 2012 capitalexpenditure budget. To the extent we repay borrowings under our credit agreement, additional borrowingswill be available to be used to fund our 2012 capital expenditure budget. However, we may determine torevise our 2012 capital expenditure budget based on the then current oil and natural gas prices and theoutcome of our drilling programs. In addition, we may spend some of the net proceeds we receive from thisoffering or additional borrowings under our credit agreement to consummate acquisitions of interests andacreage not contemplated by our 2012 capital expenditure budget if we are presented with attractiveacquisition opportunities. Management has broad discretion in applying the net proceeds we receive fromthis offering. Our shareholders may not agree with the manner in which our management chooses to allocateand spend the net proceeds we receive from this offering. The failure of management to apply these fundseffectively will have a material adverse effect on our business, financial condition, results of operations andcash flows. Pending their use, we may invest our net proceeds from this offering in a manner that does notproduce income or that loses value.

Because We Are a Relatively Small Company, the Requirements of Being a Public Company, IncludingCompliance with the Reporting Requirements of the Securities Exchange Act of 1934, as Amended, and theRequirements of the Sarbanes-Oxley Act, May Strain Our Resources, Increase Our Costs and DistractManagement; and We May Be Unable to Comply with these Requirements in a Timely or Cost-EffectiveManner.

As a public company with listed equity securities, we will need to comply with new laws, regulationsand requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley Act, related regulations of the SEC and the requirements of the NYSE, with which we are notrequired to comply as a private company. Complying with these statutes, regulations and requirements willoccupy a significant amount of time of our board of directors and management and will significantlyincrease our costs and expenses, which we cannot estimate accurately at this time. We will need to:

• institute a more comprehensive compliance function;

• establish and maintain a system of internal controls over financial reporting in compliance with therequirements of Section 404 of the Sarbanes-Oxley Act and the related rules and regulations of theSEC and the Public Company Accounting Oversight Board;

• comply with rules promulgated by the NYSE;

• prepare and distribute periodic public reports in compliance with our obligations under the federalsecurities laws;

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• establish new internal policies, such as those relating to disclosure controls and procedures andinsider trading;

• involve and retain to a greater degree outside counsel and accountants in the above activities;

• establish an internal audit function; and

• establish an investor relations function.

In addition, we also expect that being a public company subject to these rules and regulations mayrequire us to accept less director and officer liability insurance coverage than we desire or to incursubstantial costs to obtain coverage. These factors could also make it more difficult for us to attract andretain qualified members of our board of directors, particularly to serve on our audit committee, andqualified executive officers.

If Any of the Material Weaknesses Previously Identified by Our Independent Registered Public AccountantsPersist or if We Fail to Establish and Maintain Effective Internal Control over Financial Reporting in theFuture, Our Ability to Accurately Report Our Financial Results Could Be Adversely Affected.

Prior to the completion of this offering, we have been a private company and have maintained internalcontrols and procedures in accordance with being a private company. We have maintained limitedaccounting personnel to perform our accounting processes and limited supervisory resources with which toaddress our internal control over financial reporting. In connection with our audit for the year endedDecember 31, 2010, our independent registered public accountants identified and communicated materialweaknesses related to accounting for deferred income taxes, impairment of oil and natural gas properties,assessment of unproved and unevaluated properties and the administration of our stock plan. A materialweakness is a control deficiency, or a combination of control deficiencies, in internal control over financialreporting, such that there is a reasonable possibility that a material misstatement of our annual and interimfinancial statements will not be prevented or detected on a timely basis.

We have begun the process of evaluating our internal control over financial reporting and will continueto work with our auditors to put into place new accounting process and control procedures to address theissues set forth above. However, we will not complete this process until well after this offering iscompleted. We cannot predict the outcome of this process at this time.

We are not currently required to comply with the SEC’s rules implementing Section 404 of theSarbanes-Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of ourinternal control over financial reporting for that purpose. Upon becoming a public company, we will berequired to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act, which willrequire our management to certify financial and other information in our quarterly and annual reports and toprovide an annual management report on the effectiveness of our internal control over financial reporting.We will not be required to make our first assessment of our internal control over financial reporting until theyear following the year that our first annual report is filed or required to be filed with the SEC. To complywith the requirements of being a public company, we will need to upgrade our systems, includinginformation technology, implement additional financial and management controls, reporting systems andprocedures and hire additional accounting and financial reporting staff.

Further, our independent registered public accountants are not yet required to formally attest to theeffectiveness of our internal control over financial reporting until the year following the year that our first

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annual report is required to be filed with the SEC. Once they are required to do so, our independentregistered public accountants may issue a report that is adverse in the event it is not satisfied with the levelat which our controls are documented, designed, operated or reviewed. Our remediation efforts may notenable us to remedy or avoid material weaknesses in the future.

Our efforts to develop and maintain our internal controls may not be successful, and we may be unableto maintain effective controls over our financial processes and reporting in the future and comply with thecertification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Further, ourremediation efforts may not enable us to remedy or avoid material weaknesses in the future. Any failure toremediate deficiencies and to develop or maintain effective controls, or any difficulties encountered in ourimplementation or improvement of our internal control over financial reporting, could result in materialmisstatements that are not prevented or detected on a timely basis, which could potentially subject us tosanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective internal controlscould also cause investors to lose confidence in our reported financial information.

We Do Not Presently Intend to Pay Any Cash Dividends on or Repurchase Any Shares of Our Common Stock.

We do not presently intend to pay any cash dividends on our common stock. Any payment of futuredividends will be at the discretion of the board of directors and will depend on, among other things, ourearnings, financial condition, capital requirements, level of indebtedness, statutory and contractualrestrictions applying to the payment of dividends and other considerations that our board of directors deemsrelevant. Cash dividend payments in the future may only be made out of legally available funds and, if weexperience substantial losses, such funds may not be available. In addition, certain covenants in our creditagreement may limit our ability to pay dividends or repurchase shares of our common stock. While theseprohibitions exist, we are prohibited from the payment of dividends and the repurchase of shares of ourcommon stock without a waiver from our lenders. Accordingly, you may have to sell some or all of yourcommon stock in order to generate cash flow from your investment and there is no guarantee that the priceof our common stock that will prevail in the market after this offering may never exceed the price paid byyou in this offering.

Future Sales of Shares of Our Common Stock by Existing Shareholders and Future Offerings of OurCommon Stock by Us Could Depress the Price of Our Common Stock.

The market price of our common stock could decline as a result of sales of a large number of shares ofour common stock in the market after this offering, and the perception that these sales could occur may alsodepress the market price of our common stock. Based on 43,053,193 shares outstanding at January 16,2012, upon completion of this offering, we will have outstanding approximately 54,719,860 shares ofcommon stock, and in addition to the shares sold in this offering, 54,584,284 shares of common stock willbe immediately freely tradable, without restriction, in the public market, except to the extent the shares areheld by any of our affiliates. 42,440,339 of our shares, including all shares held by our officers, directorsand selling shareholders (without taking into account the shares sold by the selling shareholders), aresubject to lock-up agreements that prohibit the disposition of those shares during the 180-day periodbeginning on the date of the final prospectus related to this offering, except with the prior written consent ofRBC Capital Markets, LLC and subject to certain exceptions. After the expiration of the 180-day restrictedperiod, all of these shares may be sold in the public market in the United States, subject to prior registrationin the United States, if required, or reliance upon an exemption from U.S. registration, including, in the caseof shares held by affiliates or control persons, compliance with the volume restrictions of Rule 144.

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If our existing shareholders sell, or indicate an intent to sell, substantial amounts of our common stockin the public market after any contractual lockup and other legal restrictions on resale discussed in thisprospectus lapse, the trading price of our common stock could decline significantly and could decline belowthe initial public offering price. Sales of our common stock may make it more difficult for us to sell equitysecurities in the future at a time and at a price that we deem appropriate. These sales also could cause ourstock price to fall and make it more difficult for you to sell shares of our common stock.

As soon as practicable after effectiveness of the registration statement of which this prospectus is apart, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of4,739,500 shares of our common stock issuable or reserved for issuance under our 2003 Stock and IncentivePlan and our 2012 Long-Term Incentive Plan. Subject to the satisfaction of vesting conditions, theexpiration of lockup agreements and certain restrictions on sales by affiliates, shares registered under aregistration statement on Form S-8 will be available for resale immediately in the public market withoutrestriction.

We may also sell additional shares of common stock or securities convertible into common stock insubsequent offerings. We cannot predict the size of future issuances of our common stock or convertiblesecurities or the effect, if any, that future issuances and sales of shares of our common stock or convertiblesecurities will have on the market price of our common stock.

Provisions of Our Certificate of Formation, Bylaws and Texas Law May Have Anti-Takeover Effects thatCould Prevent a Change in Control Even if It Might Be Beneficial to Our Shareholders.

Our certificate of formation and bylaws contain, or will contain upon completion of this offering,certain provisions that may discourage, delay or prevent a merger or acquisition that our shareholders mayconsider favorable. These provisions include:

• authorization for our board of directors to issue preferred stock without shareholder approval;

• a classified board of directors so that not all members of our board of directors are elected at onetime;

• the prohibition of cumulative voting in the election of directors; and

• a limitation on the ability of shareholders to call special meetings to those owning at least 25% ofour outstanding shares of common stock.

Provisions of Texas law also may discourage, delay or prevent someone from acquiring or mergingwith us, which may cause the market price of our common stock to decline. Under Texas law, a shareholderwho beneficially owns more than 20% of our voting stock, or any “affiliated shareholder,” cannot acquireus for a period of three years from the date this person became an affiliated shareholder, unless variousconditions are met, such as approval of the transaction by our board of directors before this person becamean affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting sharesnot beneficially owned by the affiliated shareholder. See “Description of Capital Stock — BusinessCombinations Under Texas Law.”

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Our Board of Directors can Authorize the Issuance of Preferred Stock, which Could Diminish the Rights ofHolders of Our Common Stock, and Make a Change of Control of the Company More Difficult Even if itmight Benefit Our Shareholders.

Our board of directors is authorized to issue shares of preferred stock in one or more series and to fixthe voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we mayissue shares of preferred stock with a preference over our common stock with respect to dividends ordistributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rightsof the holders of common stock. Issuances of preferred stock, depending upon the rights, preferences anddesignations of the preferred stock, may have the effect of delaying, deterring or preventing a change ofcontrol of the company, even if that change of control might benefit our shareholders.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks anduncertainties, many of which are beyond our control. All statements, other than statements of historical factincluded in this prospectus, regarding our strategy, future operations, financial position, estimated revenuesand losses, projected costs and cash flows, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,”“estimate,” “expect,” “may,” “should,” “continue,” “predict,” “potential,” “project” and similar expressionsare intended to identify forward-looking statements, although not all forward-looking statements containsuch identifying words.

Forward-looking statements may include statements about our:

• business strategy;

• reserves;

• technology;

• cash flows and liquidity;

• financial strategy, budget, projections and operating results;

• oil and natural gas realized prices;

• timing and amount of future production of oil and natural gas;

• availability of drilling and production equipment;

• availability of oil field labor;

• the amount, nature and timing of capital expenditures, including future exploration anddevelopment costs;

• availability and terms of capital;

• drilling of wells;

• competition and government regulations;

• marketing of oil and natural gas;

• exploitation projects or property acquisitions;

• costs of exploiting and developing our properties and conducting other operations;

• general economic conditions;

• competition in the oil and natural gas industry;

• effectiveness of our risk management and hedging activities;

• environmental liabilities;

• counterparty credit risk;

• governmental regulation and taxation of the oil and natural gas industry;

• developments in oil-producing and natural gas-producing countries;

• uncertainty regarding our future operating results;

• estimated future reserves and present value thereof; and

• plans, objectives, expectations and intentions contained in this prospectus that are not historical.

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All forward-looking statements speak only at the date of this prospectus. You should not place unduereliance on these forward-looking statements. Although we believe that our plans, intentions andexpectations reflected in or suggested by the forward-looking statements we make in this prospectus arereasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Wedisclose important factors that could cause our actual results to differ materially from our expectationsunder “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results ofOperations” and elsewhere in this prospectus. These cautionary statements qualify all forward-lookingstatements attributable to us or persons acting on our behalf. We do not undertake any obligation to updateor revise publicly any forward-looking statements except as required by law, including the securities laws ofthe United States and the rules and regulations of the SEC.

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USE OF PROCEEDS

We will receive net proceeds of approximately $127.6 million from the sale of the common stockoffered by us after deducting estimated expenses of approximately $3.0 million and estimated underwritingdiscounts and commissions of approximately $9.4 million. If the underwriters’ over-allotment option isexercised in full, we estimate that our net proceeds will be approximately $135.4 million. We will notreceive any proceeds from the sale of shares of our common stock by the selling shareholders, includingwith respect to any sale of shares by the selling shareholders as a result of the exercise of the underwriters’over-allotment option.

Initially, we intend to use the net proceeds we receive from this offering to repay the then outstandingborrowings under our credit agreement ($123.0 million outstanding at January 27, 2012, excludingoutstanding letters of credit). Following the application of the net proceeds we receive from this offering,we will have approximately $98.7 million available for potential future borrowings under our creditagreement (after giving effect to outstanding letters of credit). We intend to use the remaining net proceedsfrom this offering, our cash from operations and available borrowings under our credit agreement to fundour 2012 capital expenditure requirements. As a result of our anticipated increases in production andreserves, we expect to have a sufficient increase in our cash flows from operations during the year endingDecember 31, 2012, as compared to our cash flows from operations in prior periods, as well as a sufficientincrease in the borrowing base under our credit agreement to help fund our 2012 capital expenditure budget.A majority of our anticipated increase in cash flows during the year ending December 31, 2012 is expectedto come from our exploration activities on unproved properties at September 30, 2011 in the Eagle Fordshale play assuming such exploration activities are successful. These anticipated increases in our cash flowsfrom operations are based upon current oil and natural gas prices and the hedges we currently have in place.If our exploration activities result in less cash flows than anticipated, we may seek additional sources ofcapital, including through borrowings under our credit agreement (assuming availability under ourborrowing base) or from the issuance of additional equity or debt securities. In addition, we may modify ourplanned capital expenditure budget for 2012 accordingly. Exploration activities are subject to a number ofrisks and uncertainties that could impact our ability to sufficiently increase our reserves, cash flows fromoperations and borrowing base under our credit agreement. See “Risk Factors — Our Exploration,Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed OurCash Flows From Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capitalon Satisfactory Terms, Which Could Adversely Affect Our Future Growth” and “—Drilling for andProducing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with ManyUncertainties That Could Adversely Affect Our Business.” Although we have no current plans or proposals,pending application of the portion of our net proceeds to fund our 2012 capital expenditure requirements,we may be presented with other opportunities for acquisitions of interests or acreage. In that case, we maydecide to use a portion of the net proceeds to finance these acquisitions and use cash flows from operationsor additional borrowings under our credit agreement to fund our 2012 capital expenditure requirements,when necessary.

We intend to use the following amounts of the net proceeds for the above uses:

Use of Net ProceedsAmount

(in millions)

Repayment of senior secured revolving credit agreement . . . . . . . . . . . . . . . $123.0Payment of a portion of 2012 capital expenditure requirements . . . . . . . . . . 4.6

Total net proceeds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $127.6

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In December 2011, we amended and restated our senior secured revolving credit agreement. Thisamendment increased the maximum facility amount from $150 million to $400 million. Borrowings arelimited to the lesser of $400 million or the borrowing base, which will be $100 million immediatelyfollowing this offering. Comerica Bank serves as administrative agent of our credit agreement, whichmatures in December 2016. At January 27, 2012, all borrowings under our credit agreement bore interest ata variable rate of 3.25% plus a Eurodollar-based rate per annum, which equated to approximately 3.5% perannum. For more information regarding our amended and restated credit agreement, see “Management’sDiscussion and Analysis of Financial Condition and Results of Operations — Liquidity and CapitalResources — Credit Agreement.” Affiliates of certain of the underwriters are lenders under our seniorsecured revolving credit agreement and, accordingly, will receive a portion of the proceeds from thisoffering. Please read “Underwriting — Conflicts of Interest.”

Borrowings under the credit agreement were incurred from December 2010 through January 2012 tofinance acquisitions of acreage and ongoing drilling and completion operations. Upon consummation of thisoffering and application of the net proceeds we receive in the manner described above, we will haveavailable borrowings under our credit agreement to finance our capital expenditure requirements. Weanticipate that we may need to access future borrowings under our credit agreement within 30 daysfollowing completion of this offering to fund a portion of our 2012 capital expenditure requirements inexcess of amounts available from our cash flows and the net proceeds of this offering.

The selling shareholders will receive net proceeds of approximately $18.8 million from their sale of1,666,667 shares of common stock in this offering, or approximately $33.4 million if the underwritersexercise their over-allotment option in full, and in each case after deducting estimated underwritingdiscounts and commissions. We will pay all expenses related to this offering, other than underwritingdiscounts and commissions related to the shares sold by the selling shareholders. Certain sellingshareholders that are selling 243,460 shares in this offering will not be required to pay underwritingdiscounts or commissions. See “Principal and Selling Shareholders” and “Underwriters.”

While we expect to use the net proceeds from this offering in the manner described above, includingfor potential acquisitions of interests and/or acreage (although we have no current plans to do so), theultimate amount of capital we will expend may fluctuate materially based on market conditions and ourdrilling results. Our future financial condition and liquidity will be impacted by, among other factors, ourlevel of production of oil and natural gas and the prices we receive from the sale thereof, the outcome of ourexploration and drilling programs, the number of commercially viable oil and natural gas discoveries madeand the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries toproduction, and the actual cost of exploration and development of our oil and natural gas assets. We intendto invest any net proceeds from this offering that exceed the pay off amount of our credit agreement asdescribed above in U.S. treasury bonds or investment grade instruments until otherwise needed.

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DIVIDEND POLICY

We do not anticipate declaring or paying any cash dividends to holders of our common stock in theforeseeable future. We currently intend to retain future earnings to finance the expansion of our business.Our future dividend policy is within the discretion of our board of directors and will depend upon variousfactors, including our results of operations, financial condition, capital requirements and investmentopportunities. In addition, certain covenants in our credit agreement may limit our ability to pay dividendson our common stock.

In addition, prior to consummation of this offering, the holders of our Class B common stock areentitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of funds legallyavailable for the payment of dividends. These dividends accrue and are payable quarterly at the rate of$0.06-2/3 per share of Class B common stock outstanding. For the years ended December 31, 2010 and2009, we declared dividends on our outstanding shares of Class B common stock totaling $274,853 in eachyear. For the nine months ended September 30, 2011, we declared dividends on our outstanding shares ofClass B common stock totaling $206,140. Upon the automatic conversion of the outstanding shares ofClass B common stock at the closing of this offering, the right of the holders of Class B common stock todividends will terminate. Any accrued but unpaid dividends existing at the time of such conversion will bepaid to the holders of the Class B common stock upon conversion.

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CAPITALIZATION

The following table sets forth our capitalization at September 30, 2011. Our capitalization is presented:

• on an actual basis; and

• on an as adjusted basis to give effect to this offering (assuming aggregate net proceeds of $127.6million are received by us), the application of the estimated net proceeds to be received by us torepay then outstanding borrowings under our credit agreement ($123.0 million outstanding atJanuary 27, 2012, excluding outstanding letters of credit), with the balance being added to cash andcash equivalents until it is used to fund capital requirements, the issuance of 285,000 shares ofcommon stock by us to certain holders of stock options prior to consummation of this offering inconnection with the exercise of their stock options at an exercise price of $9.00 per share and theconversion of our Class B common stock into Class A common stock upon consummation of thisoffering.

You should read the following table in conjunction with “Use of Proceeds,” “Selected HistoricalConsolidated and Other Financial Data,” “Management’s Discussion and Analysis of Financial Conditionand Results of Operations” and our historical consolidated financial statements and related notes theretoappearing elsewhere in this prospectus.

At September 30, 2011

Actual As Adjusted

(In thousands except for shares)Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7,768 $ 14,883Certificates of deposit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,085 2,085Debt:

Short-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,000 –Long-term debt(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60,000 –

Shareholders’ equity: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Class A common stock, $0.01 par value, 80,000,000 shares authorized; 42,907,843 shares issued and

41,728,668 shares outstanding, actual; 55,890,210 shares issued and 54,711,035 shares outstanding, asadjusted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 429 559

Class B common stock, $0.01 par value, 2,000,000 shares authorized; 1,030,700 shares issued andoutstanding, actual; 0 shares issued and outstanding, as adjusted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 –

Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 263,933 393,928Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,931 14,931Treasury stock, at cost, 1,179,175 shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (10,765) (10,765)

Total shareholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $268,538 $398,653

Total capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $328,538 $398,653

(1) At January 27, 2012, the borrowing base under our credit agreement was $125.0 million, and we had $123.0 million in borrowingsoutstanding, excluding outstanding letters of credit. Approximately $0.7 million remained available for additional borrowings. See“Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — CreditAgreement.”

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DILUTION

Purchasers of the common stock in this offering will experience immediate and substantial dilution inthe net tangible book value per share of the common stock for accounting purposes. Our net tangible bookvalue at September 30, 2011 was approximately $269 million, or $6.28 per share of common stock. Proforma net tangible book value per share is determined by dividing our pro forma tangible net worth(tangible assets less total liabilities) by the total number of outstanding shares of common stock that will beoutstanding immediately prior to the closing of this offering.

After giving effect to the sale of the shares in this offering and further assuming the receipt of theestimated net proceeds to be received by us (after deducting estimated discounts and expenses of thisoffering), our as adjusted net tangible book value at September 30, 2011 would have been approximately$398.7 million, or $7.29 per share. This represents an immediate increase in the net tangible book value of$1.01 per share to our existing shareholders and an immediate dilution (i.e., the difference between theoffering price and the adjusted net tangible book value after this offering) to new investors purchasingshares in this offering of $4.71 per share. The following table illustrates the per share dilution to newinvestors purchasing shares in this offering:

Assumed initial public offering price per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $12.00Net tangible book value per share at September 30, 2011 . . . . . . . . . . . . . . . . . . . . . . . 6.28Increase per share attributable to new investors in this offering . . . . . . . . . . . . . . . . . . 1.01

As adjusted net tangible book value per share after giving effect to this offering . . . . . . . . . 7.29

Dilution in as adjusted net tangible book value per share to new investors in thisoffering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4.71

The following table summarizes, on an as adjusted basis at September 30, 2011, the total number ofshares of common stock owned by existing shareholders (assuming (i) the issuance by us of 285,000 sharesof common stock to certain holders of stock options prior to consummation of this offering in connectionwith the exercise of their stock options at an exercise price of $9.00 per share and (ii) the conversion of ourClass B common stock as described under “Description of Capital Stock”) and to be owned by newinvestors, the total consideration paid, and the average price per share paid by our existing shareholders andto be paid by new investors in this offering at $12.00, calculated before deduction of estimated underwritingdiscounts and commissions:

Shares Acquired Total Consideration Average Priceper ShareNumber Percent Amount Percent

Existing shareholders(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43,044,368 78.7 $256,738 64.7 $ 5.96New investors(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,666,667 21.3 140,000 35.3 12.00

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54,711,035 100.0% $396,738 100.0% $ 7.25

(1) The number of shares disclosed for the existing shareholders includes 1,666,667 shares being sold by the selling shareholders in thisoffering. The number of shares disclosed for the new investors does not include the shares being purchased by the new investors from theselling shareholders in this offering.

Apart from the information set forth in the tables above, assuming the underwriters’ over-allotment isexercised in full, sales by us in this offering will reduce the percentage of shares held by existingshareholders, without giving effect to the shares being sold by the selling shareholders in this offering, to77.7% and will increase the number of shares held by new investors to 12,366,667, or 22.3% on an asadjusted basis at September 30, 2011.

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SELECTED HISTORICAL CONSOLIDATED AND OTHER FINANCIAL DATA

You should read the following selected financial data in conjunction with “Corporate Reorganization,”“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and ourhistorical consolidated financial statements and related notes thereto included elsewhere in this prospectus.The financial information included in this prospectus may not be indicative of our future results ofoperations, financial position and cash flows.

The following selected financial information is summarized from our results of operations for the five-year period ended December 31, 2010 and selected consolidated balance sheet data at December 31, 2010,2009, 2008, 2007 and 2006 and our results of operations for the nine months ended September 30, 2011 and2010 and the consolidated balance sheet data at September 30, 2011 and 2010 and should be read inconjunction with the consolidated financial statements at the years ended December 31, 2010, 2009 and2008 and the nine month periods ended September 30, 2011 and 2010, and the notes thereto includedherewith.


September 30,

2010 2009 2008 2007 2006 2011 2010

(Unaudited) (Unaudited)(In thousands)Statement of operations data:

Revenues:Oil and natural gas revenues . . . . . . . . . . . . . . . . . . . . . . . $34,042 $ 19,039 $ 30,645 $13,988 $ 14,678 $ 52,009 $25,182Realized gain (loss) on derivatives . . . . . . . . . . . . . . . . . . 5,299 7,625 (1,326) 213 – 4,237 2,988Unrealized gain (loss) on derivatives . . . . . . . . . . . . . . . . 3,139 (2,375) 3,592 (211) – 1,534 5,813

Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . 42,480 24,289 32,911 13,990 14,678 57,780 33,983Expenses:

Production taxes and marketing . . . . . . . . . . . . . . . . . . . . 1,982 1,077 1,639 779 896 4,801 1,235Lease operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,284 4,725 4,667 3,099 3,075 5,639 3,801Depletion, depreciation and amortization . . . . . . . . . . . . . 15,596 10,743 12,127 7,889 10,950 22,578 10,931Accretion of asset retirement obligations . . . . . . . . . . . . . 155 137 92 70 55 158 107Full-cost ceiling impairment . . . . . . . . . . . . . . . . . . . . . . . – 25,244 22,195 – 56,504 35,673 –General and administrative . . . . . . . . . . . . . . . . . . . . . . . . 9,702 7,115 8,252 5,189 5,407 9,395 6,793

Total expenses . . . . . . . . . . . . . . . . . . . . . . . . . 32,719 49,041 48,972 17,026 76,887 78,244 22,867Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,761 (24,752) (16,061) (3,036) (62,209) (20,464) 11,116

Other income (expense):Net gain (loss) on asset sales and inventory

impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (224) (379) 136,977 – – – –Interest and other income . . . . . . . . . . . . . . . . . . . . . . . . . 364 781 2,984 2,736 2,063 248 300Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3) – – – – (461) –

Total other income (expense) . . . . . . . . . . . . . . . . . . 137 402 139,962 2,736 2,063 (213) 300Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,377 $(14,425) $103,878 $ (300) $(60,146) $(13,725) $ 7,373

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2010 2009 2008 2007 2006 2011 2010

ActualAs

Adjusted(1)

(Unaudited) (Unaudited) (Unaudited)(In thousands)Balance sheet data:Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 21,060 $104,230 $150,768 $ 9,017 $ 43,183 $ 7,768 $ 14,883 $ 38,618Certificates of deposit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,349 15,675 20,782 – – 2,085 2,085 7,429Short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – – 57,925 – – – –Net property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . 303,880 142,078 125,261 105,814 63,062 350,279 388,279 227,052Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 346,382 277,400 314,539 179,152 112,628 383,244 428,359 291,423Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30,097 8,868 35,475 5,541 5,878 50,102 25,102 19,396Long term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34,408 4,210 2,059 1,568 878 64,604 4,604 8,125Total shareholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . $281,877 $264,321 $277,005 $172,043 $105,872 $268,538 $398,653 $263,902


September 30,

2010 2009 2008 2007 2006 2011 2010

(Unaudited) (Unaudited)(In thousands)Other financial data:Net cash provided by operating activities . . . . . . . . . . . . . . . . $ 27,273 $ 1,791 $ 25,851 $ 7,881 $ 1,570 $ 34,443 $ 21,390Net cash (used in) provided by investing activities . . . . . . . . (147,334) (49,415) 115,481 (108,296) (49,501) (107,772) (78,718)

Oil and natural gas properties capital expenditures . . . . (159,050) (54,244) (104,119) (50,310) (51,932) (104,733) (86,031)Expenditures for other property and equipment . . . . . . . (1,610) (307) (3,012) (1,300) (3,127) (3,303) (934)

Net cash provided by (used in) financing activities . . . . . . . . 36,891 1,086 419 66,250 73,876 60,037 (8,284)Adjusted EBITDA(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 23,635 $ 15,184 $ 18,411 $ 8,091 $ 7,582 $ 37,550 $ 17,133

(1) As adjusted to give effect to (a) this offering (assuming aggregate net proceeds of $127.6 million are received by us), (b) the application of the netproceeds to be received by us to repay the then outstanding borrowings under our credit agreement ($123.0 million less outstanding letters of credit), (c)$38.0 million being added to property and equipment reflecting the use of $38.0 million in additional borrowings under our credit agreement betweenSeptember 30, 2011 and January 27, 2012, (d) the balance of the net proceeds from this offering being added to cash and cash equivalents to fund aportion of our 2012 capital expenditure budget and (e) the proceeds to be received by us as a result of the issuance of 285,000 shares of common stockto certain holders of stock options prior to the consummation of this offering in connection with the exercise of their stock options at an exercise price of$9.00 per share.

(2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our netincome (loss) and net cash provided by operating activities, see “Summary Financial, Reserves and Operating Data.”

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MANAGEMENT’S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should beread in conjunction with our consolidated financial statements and related notes appearing elsewhere inthis prospectus. The following discussion contains “forward-looking statements” that reflect our futureplans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections,intentions or beliefs about future events may, and often do, vary from actual results and the differences canbe material. Some of the key factors which could cause actual results to vary from our expectations includechanges in oil or natural gas prices, the timing of planned capital expenditures, availability of acquisitions,uncertainties in estimating proved reserves and forecasting production results, operational factors affectingthe commencement or maintenance of producing wells, the condition of the capital markets generally, aswell as our ability to access them, the proximity to and capacity of transportation facilities, uncertaintiesregarding environmental regulations or litigation and other legal or regulatory developments affecting ourbusiness, as well as those factors discussed below and elsewhere in the prospectus, all of which are difficultto predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed maynot occur. See “Cautionary Note Regarding Forward-Looking Statements.”

Overview

We are an independent energy company engaged in the exploration, development, acquisition andproduction of oil and natural gas resources in the United States, with a particular emphasis on oil andnatural gas shale plays and other unconventional resources. Our current operations are located primarily inthe Eagle Ford shale play in south Texas and the Haynesville shale play in northwest Louisiana and eastTexas. These plays are a key part of our growth strategy, and we believe they currently represent two of themost active and economically viable unconventional resource plays in North America. We expect themajority of our near-term capital expenditures will focus on increasing our production and reserves from theEagle Ford and Haynesville shale plays as we seek to capitalize on the relative economics of each play. Inaddition to these primary operating areas, we have significant acreage positions in southeast New Mexicoand west Texas and in southwest Wyoming and adjacent areas in Utah and Idaho where we continue toidentify new oil and natural gas prospects.

We were founded in July 2003 by Mr. Joseph Wm. Foran and Mr. Scott E. King, and we drilled ourfirst well in 2004. Since that time, we have drilled or participated in 213 wells through September 30, 2011,including 83 Haynesville and six Eagle Ford wells. At September 30, 2011, based on the reserves audit byour independent reservoir engineers, we had 161.8 Bcfe of estimated proved reserves with a PV-10 of$155.2 million and a Standardized Measure of $143.4 million. At September 30, 2011, 35% of ourestimated proved reserves were proved developed reserves and 96% of our estimated proved reserves werenatural gas. We grew our average daily production by 162% from 9.0 MMcfe per day from the year endedDecember 31, 2008 to 23.6 MMcfe per day for the year ended December 31, 2010. As a result of initialproduction from several wells that were completed in 2011, our average daily production for thenine months ended September 30, 2011 was approximately 42.5 MMcfe per day.

Our business success and financial results are dependent on many factors beyond our control, such aseconomic, political and regulatory developments, as well as competition from other sources of energy.Commodity price volatility, in particular, is a significant risk factor for us. Commodity prices are affectedby changes in market supply and demand, which is impacted by overall economic activity, weather, pipelinecapacity constraints, inventory storage levels, natural gas price differentials and other factors. Prices for oiland natural gas will affect the cash flows available to us for capital expenditures and our ability to borrow

57

and raise additional capital. Declines in oil or natural gas prices would not only reduce our revenues, butcould also reduce the amount of oil and/or natural gas that we can produce economically, and as a result,could have an adverse effect on our financial condition, results of operations, cash flows and reserves.Because we produce more natural gas than oil at the present time and expect to continue to do so in the nearterm, we will face more risks associated with fluctuations in the price of natural gas. Since one of ourcurrent business strategies is to focus on increasing our oil and liquids production, we will face increasedrisk in the future associated with fluctuations in the price of oil.

In response to the recent commodity price environment, and in particular, the general decline in naturalgas prices since July 2008 in contrast with the rebound in oil prices since February 2009, we have sought tobalance our exploration and development plans by targeting more oil prone reservoirs, such as the EagleFord shale. While most of our historical and current production is natural gas, we believe that our futureproduction profile will reflect a more balanced oil and natural gas commodity mix as a result of our strategicshift to target more oil development than we have historically.

One of the biggest challenges we face in the development of our Eagle Ford and Haynesville shaleacreage is associated with service costs, and particularly in the Eagle Ford play, pipeline infrastructure andthe shortage of stimulation equipment and service dates necessary to stimulate these wells. Due to theincreased activity in these areas, service costs have continued to rise and the availability of completioncrews has decreased. We believe that reducing drilling and particularly completion costs will be essential tothe successful development and profitability of the Eagle Ford and Haynesville shale plays. See “RiskFactors — The unavailability or high cost of drilling rigs, completion equipment and services, supplies andpersonnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability toestablish and execute exploration and development plans within budget and on a timely basis, which couldhave a material adverse effect on our financial condition, results of operations and cash flows.”

We believe that our general and administrative expenses will increase in connection with thecompletion of this offering as a result of us operating as a public company. This increase will consistprimarily of legal and accounting fees and additional expenses associated with compliance with theSarbanes-Oxley Act and other regulations and increases in our staff compensation and other ongoinggeneral and administrative expenses necessary to maintain and grow a publicly traded exploration andproduction company. A large part of this increase will be due to the cost of accounting support services,filing annual and quarterly reports with the SEC, investor relations activities, directors’ fees, incrementaldirectors’ and officers’ liability insurance costs and transfer and registrar agent fees. As a result, we believethat our general and administrative expenses for future periods will increase significantly. Our consolidatedfinancial statements following the completion of this offering will reflect the impact of these increasedexpenses and affect the comparability of our financial statements with periods before the completion of thisoffering.

Revenues

Our revenues are derived primarily from the sale of oil and natural gas production. Our revenues mayvary significantly from period to period as a result of changes in volumes of production sold or changes inoil or natural gas prices.

Realized gain (loss) on derivatives. We use commodity derivative financial instruments to mitigate ourexposure to fluctuations in natural gas prices. This revenue item includes the net realized cash gains andlosses associated with the settlement of these derivative financial instruments for a given reporting period.

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Unrealized gain (loss) on derivatives. We use commodity derivative financial instruments to mitigateour exposure to fluctuations in natural gas prices. This revenue item recognizes the non-cash change in thefair value of our open derivative contracts between reporting periods.

The following table summarizes our revenues and production data for the periods indicated:


September 30,

2010 2009 2008 2011 2010

(Unaudited) (Unaudited)Operating Results:Revenues (in thousands):

Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,506 $ 1,719 $ 3,653 $10,468 $ 1,831Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31,535 17,320 26,992 41,541 23,351

Total oil and natural gas revenues . . . . . . . . . . . . . . . . . . . . . . . . . . 34,042 19,039 30,645 52,009 25,182Realized gain (loss) on derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,299 7,625 (1,326) 4,237 2,988Unrealized gain (loss) on derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,139 (2,375) 3,592 1,534 5,813

Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $42,480 $24,289 $32,911 $57,780 $33,983

Net Production Volumes:Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 30 37 113 24Natural gas (Bcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4 4.8 3.1 10.9 5.9

Total natural gas equivalents (Bcfe) . . . . . . . . . . . . . . . . . . . . . . . . 8.6 5.0 3.3 11.6 6.0Average net daily production (MMcfe/d) . . . . . . . . . . . . . . . . . . . . 23.6 13.7 9.0 42.5 22.0

Average Sales Prices:Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 76.39 $ 57.72 $ 98.59 $ 92.71 $ 74.59Natural gas, with realized derivatives (per Mcf) . . . . . . . . . . . . . . . . . . . $ 4.38 $ 5.17 $ 8.32 $ 4.19 $ 4.49Natural gas, without realized derivatives (per Mcf) . . . . . . . . . . . . . . . . $ 3.75 $ 3.59 $ 8.75 $ 3.80 $ 3.98

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Oil and natural gas revenues. Our oil and natural gas revenues increased by $26.8 million to $52.0million, or an increase of about 107%, for the nine months ended September 30, 2011, as compared to thenine months ended September 30, 2010. This increase in oil and natural gas revenues corresponds with anincrease of about 93% in our oil and natural gas production to 11.6 Bcfe for the nine months endedSeptember 30, 2011 from 6.0 Bcfe for the nine months ended September 30, 2010. This increasedproduction was primarily due to drilling operations in the Haynesville shale, but also reflects initialproduction from our first two operated wells in the Eagle Ford shale. A portion of the increased oil andnatural gas revenues was also attributable to the approximate five-fold increase in our oil production for thenine months ended September 30, 2011 as compared to the nine months ended September 30, 2010, as wellas to the increase of about $18.00 per Bbl in the average price we received for this oil production during thenine months ended September 30, 2011 as compared to the same period in 2010.

Realized gain (loss) on derivatives. Our realized gain on derivatives increased by approximately$1.2 million to $4.2 million for the nine months ended September 30, 2011 from $3.0 million for the ninemonths ended September 30, 2010. The realized gain from our open natural gas costless collar contractsincreased primarily as a result of the decline in natural gas prices during the comparable periods. Werealized approximately $0.91 per MMBtu hedged on all of our open natural gas costless collar contractsduring the nine months ended September 30, 2011 as compared to $0.68 per MMBtu hedged on all of ouropen natural gas costless collar contracts during the nine months ended September 30, 2010.

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was $1.5 million for the ninemonths ended September 30, 2011, compared to an unrealized gain of $5.8 million for the nine months

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ended September 30, 2010. During the period from December 31, 2010 to September 30, 2011, the net fairvalue of our open natural gas costless collar contracts increased from $4.1 million to $5.6 million, resultingin an unrealized gain on derivatives of $1.5 million for the nine months ended September 30, 2011. Thisincrease in the net fair value of our open natural gas costless collar contracts was due primarily to a decreasein natural gas prices during the first nine months of 2011 as compared to the comparable period in 2010, aswell as an increase in the total number of our open contracts at September 30, 2011 as compared toDecember 31, 2010. During the period from December 31, 2009 to September 30, 2010, the net fair value ofour open natural gas costless collar contracts increased from $1.0 million to $6.8 million, resulting in anunrealized gain on derivatives of $5.8 million for the nine months ended September 30, 2010.

Year Ended December 31, 2010 as Compared to Year Ended December 31, 2009

Oil and natural gas revenues. Our oil and natural gas revenues increased by $15.0 million to$34.0 million, or an increase of about 79%, for the year ended December 31, 2010 as compared to the yearended December 31, 2009. Approximately $13.7 million of the increase was primarily due to a 72%increase in our production to 8.6 Bcfe during the year ended December 31, 2010 from 5.0 Bcfe during theyear ended December 31, 2009, and approximately $1.3 million of the increase was due to increases in theaverage prices we received for both oil and natural gas over these respective periods. For the year endedDecember 31, 2010, we received an average natural gas price of $3.75 per Mcf and an average oil price of$76.39 per Bbl as compared to an average natural gas price of $3.59 per Mcf and an average oil price of$57.72 per Bbl for the year ended December 31, 2009. Our increased production during this period wasprimarily due to drilling operations in the Haynesville shale.

Realized gain (loss) on derivatives. Our realized gain on derivatives decreased by approximately$2.3 million to $5.3 million for the year ended December 31, 2010 from $7.6 million for the year endedDecember 31, 2009. This decrease was due primarily to a decrease of about $1.50 per MMBtu in theaverage price floor of our open natural gas costless collar contracts in 2010 as compared with 2009 anddespite the increase in natural gas volumes hedged in 2010 as compared to 2009.

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was $3.1 million for the yearended December 31, 2010, compared to an unrealized loss of $2.4 million for the year ended December 31,2009. During the period from December 31, 2009 to December 31, 2010, the net fair value of our opennatural gas costless collar contracts increased from $1.0 million to $4.1 million, resulting in an unrealizedgain on derivatives of $3.1 million for the year ended December 31, 2010. This increase in the net fair valueof our open natural gas costless collar contracts was due primarily to lower natural gas prices atDecember 31, 2010 as compared to December 31, 2009. During the period from December 31, 2008 toDecember 31, 2009, the net fair value of our open natural gas costless collar contracts decreased from$3.4 million to $1.0 million, resulting in an unrealized loss on derivatives of $2.4 million for the year endedDecember 31, 2009. This decrease in the net fair value of our open natural gas costless collar contracts wasdue primarily to an approximate $2.00 per MMBtu decrease in the average floor price of our open contractsat December 31, 2009 as compared with December 31, 2008.

Year Ended December 31, 2009 as Compared to Year Ended December 31, 2008

Oil and natural gas revenues. Our oil and natural gas revenues decreased $11.6 million to$19.0 million, or a decrease of about 38%, during the year ended December 31, 2009 as compared to theyear ended December 31, 2008. Although we increased our production by 51% from 3.3 Bcfe in 2008 to5.0 Bcfe in 2009, the oil and natural gas revenues of approximately $5.8 million generated by theseincreased production volumes did not fully offset the $17.4 million decrease in oil and natural gas revenues

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attributable to a sharp decline in the prices we received for both oil and natural gas in 2009 as comparedwith 2008. For the year ended December 31, 2009, we received an average natural gas price of $3.59 perMcf and an average oil price of $57.72 per Bbl as compared to an average natural gas price of $8.75 perMcf and an average oil price of $98.59 per Bbl for the year ended December 31, 2008. Our increasedproduction during this period was due primarily to drilling operations in the Haynesville shale.

Realized gain (loss) on derivatives. Our realized gain on derivatives increased approximately $8.9million to $7.6 million during the year ended December 31, 2009 from a loss of $1.3 million during the yearended December 31, 2008. Natural gas futures prices closed above the price ceiling of many of our opennatural gas costless collar contracts during the first half of 2008, and, as a result, we were required to paythe counterparty at settlement. Natural gas prices declined sharply beginning in August 2008 and continuedto decline throughout much of 2009, and as a result, natural gas prices closed below the price floor of manyof our open costless collar contracts during almost all of 2009. As a result, we received cash from thecounterparty at settlement and our realized gain on derivatives increased significantly.

Unrealized gain (loss) on derivatives. Our unrealized loss on derivatives was $2.4 million for the yearended December 31, 2009 as compared to an unrealized gain of $3.6 million for the year endedDecember 31, 2008. During the period from December 31, 2008 to December 31, 2009, the net fair value ofour open natural gas costless collar contracts decreased from $3.4 million to $1.0 million, resulting in anunrealized loss on derivatives of $2.4 million for the year ended December 31, 2009. This decrease in thenet fair value of our open natural gas costless collar contracts was due primarily to an approximate $2.00per MMBtu decrease in the average floor price of our open contracts at December 31, 2009 as comparedwith December 31, 2008. During the period from December 31, 2007 to December 31, 2008, the net fairvalue of our open natural gas costless collar contracts increased from a liability of $0.2 million to $3.4million, resulting in an unrealized gain on derivatives of $3.6 million for the year ended December 31,2008. This increase in the net fair value of our open natural gas costless collar contracts was due to adecrease in natural gas prices and an increase in the volume of natural gas hedged at December 31, 2008 ascompared with December 31, 2007.

Expenses

Production taxes and marketing. Production taxes are paid on produced oil and natural gas based on apercentage of revenues from products sold at market prices (not hedged prices) or at fixed rates establishedby federal, state or local taxing authorities. We attempt to take advantage of all credits and exemptions inour various taxing jurisdictions. In general, the production taxes we pay tend to correlate to the changes inour oil and natural gas revenues. Marketing expenses are fees charged by the purchasers of the oil andnatural gas we produce and sell and principally include marketing, compression and transportation fees.

Lease operating expenses. Lease operating expenses are the daily costs incurred to produce oil andnatural gas, as well as the daily costs incurred to maintain our producing properties. Such costs also includefield personnel costs, utilities, chemical additives, salt water disposal, maintenance, repairs and occasionalworkover expenses related to our oil and natural gas properties.

Depletion, depreciation and amortization. Depletion, depreciation and amortization includes thesystematic expensing of the capitalized costs incurred in the acquisition, exploration and development of oiland natural gas. We use the full-cost method of accounting and accordingly, we capitalize all costsassociated with the acquisition, exploration and development of oil and natural gas properties, includingunproved and unevaluated property costs. Internal costs are capitalized only to the extent they are directlyrelated to acquisition, exploration or development activities and do not include any costs related to

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production, selling or general corporate administrative activities. Capitalized costs of oil and natural gasproperties are amortized using the unit-of-production method based upon production and estimates ofproved oil and natural gas reserves quantities. Unproved and unevaluated property costs are excluded fromthe amortization base used to determine depletion, depreciation and amortization.

Accretion of asset retirement obligations. Asset retirement obligations relate to the future costsassociated with plugging and abandonment of oil and natural gas wells, removal of equipment and facilitiesfrom leased acreage and returning such land to its original condition. We recognize the fair value of an assetretirement obligation in the period it is incurred if a reasonable estimate of fair value can be made. The assetretirement obligation is recorded as a liability at its estimated present value, with an offsetting increaserecognized in oil and natural gas properties or support equipment and facilities on the balance sheet.Periodic accretion of the discounted value of the estimated liability is recorded as an expense in ourstatement of operations.

Full-cost ceiling impairment. The net capitalized costs of oil and natural gas properties are limited tothe lower of unamortized costs less related deferred income taxes or the cost center ceiling, with any excessabove the cost center ceiling charged to operations as a full-cost ceiling impairment. The cost center ceilingis defined as the sum of (a) the present value discounted at 10 percent of future net revenues of proved oiland natural gas reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) thelower of cost or estimated fair value of unproved and unevaluated properties included in the costs beingamortized, if any, less (d) income tax effects related to differences between the book and tax basis of theproperties involved. Future net revenues from proved non-producing and proved undeveloped reserves arereduced by the estimated costs of developing these reserves. The fair value of our derivative instruments isnot included in the ceiling test computation as we do not designate these instruments as hedge instrumentsfor accounting purposes.

General and administrative expenses. General and administrative expenses include, but are not limitedto, compensation and benefits for our employees, costs of renting and maintaining our headquarters, officeservice contracts, board of directors fees, franchise taxes, stock-based compensation expense andaccounting, legal and other professional fees.

Other Income (Expense)

Net gain (loss) on asset sales and inventory impairment. This other income (expense) item includes thenet gain or loss we experience on infrequent asset sales or impairment charges associated with certainequipment held in inventory. This item also includes infrequent sales of oil and natural gas properties thatwe consider to be extraordinary when considered in relation to the normal course of our business.

Interest and other income. Interest income includes interest earned periodically on the cash and cashequivalents we hold in money market accounts composed of United States Treasury securities offering dailyliquidity and the interest earned periodically on our certificates of deposit. Other income includes incomewe receive for providing salt water disposal and natural gas transportation services to other working interestparticipants in wells that we operate.

Interest expense. Interest expense includes interest paid to our lenders as a result of borrowings underour revolving credit agreement. We finance a portion of our working capital requirements, capitalexpenditures and acquisitions with borrowings under the credit agreement, and as a result, we incur interestexpense that is affected by both fluctuations in interest rates and our financing decisions. In addition, weinclude any amortization of deferred financing costs (including origination and amendment fees),commitment fees and annual agency fees as interest expense.

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Total income tax provision (benefit). Total income tax provision (benefit) includes the net current anddeferred portions of our estimated income tax liabilities. We file a United States federal income tax returnand state tax returns in those states where we conduct oil and natural gas operations. The current portion ofour income tax provision (benefit) reflects actual income tax payments made or refunds received by us as aresult of filing these income tax returns. The deferred portion of our income tax provision is the result oftemporary timing differences between the financial statement carrying values and the tax bases of our assetsand liabilities.

The following table summarizes our operating expenses and other income (expense) for the periodsindicated:

Year EndedDecember 31,

Nine Months EndedSeptember 30,

2010 2009 2008 2011 2010

(Unaudited) (Unaudited)(In thousands, except expenses per Mcfe)Expenses:

Production taxes and marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,982 $ 1,077 $ 1,639 $ 4,801 $ 1,235Lease operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,284 4,725 4,667 5,639 3,801Depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . 15,596 10,743 12,127 22,578 10,931Accretion of asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . 155 137 91 158 107Full-cost ceiling impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 25,244 22,195 35,673 –General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,702 7,115 8,252 9,395 6,793

Total expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32,719 49,041 48,972 78,244 22,867Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,761 (24,752) (16,061) (20,464) 11,116Other income (expense):

Net gain (loss) on asset sales and inventory impairment . . . . . . . . . . . (224) (379) 136,978 – –Interest and other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 364 781 2,984 248 300Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3) – – (461) –

Total other income (expense) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137 402 139,962 (213) 300Income (loss) before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,898 (24,350) 123,901 (20,677) 11,416Total income tax provision (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,521 (9,925) 20,023 (6,952) 4,043Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,377 $(14,425) $103,878 $(13,725) $ 7,373Expenses per Mcfe:

Production taxes and marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.23 $ 0.22 $ 0.50 $ 0.41 $ 0.21Lease operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.61 $ 0.94 $ 1.41 $ 0.49 $ 0.63Depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . $ 1.81 $ 2.15 $ 3.67 $ 1.95 $ 1.82General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1.13 $ 1.42 $ 2.50 $ 0.81 $ 1.13

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Production taxes and marketing. Our production taxes and marketing expenses increased by $3.6million to $4.8 million, or an increase of approximately 289% for the nine months ended September 30,2011, as compared to the nine months ended September 30, 2010. The increase in our production taxes andmarketing expenses reflects the increases in both our oil and natural gas production and revenues by 93%and 107%, respectively, during the nine months ended September 30, 2011 as compared to the nine monthsended September 30, 2010. The majority of this increase was due to higher marketing, transportation andcompression charges on non-operated Haynesville shale production in the first nine months of 2011 ascompared to the same period in 2010. Some of this increase was also due to recently completed Haynesvilleshale wells, several of which were turned to sales or produced their first significant production volumesduring the first nine months of 2011. Although we or our outside operating partners have applied forexemptions from initial production taxes on these recently completed Haynesville shale wells, and althoughwe expect these applications will be approved by the state of Louisiana, some of these wells had not yetbeen approved for production tax exemptions at September 30, 2011. Thus, we have paid and/or accrued for

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the associated production taxes on these wells during the first nine months of 2011, although we expectthese production taxes will be refunded to us in future periods. We will adjust our production taxes andmarketing expenses accordingly when and if these production tax exemptions are approved. The remainderof the increase in production taxes and marketing expenses for the nine months ended September 30, 2011was due to production taxes paid on initial production from our first two operated Eagle Ford shale wells insouth Texas.

Lease operating expenses. Our lease operating expenses increased by $1.8 million to $5.6 million, oran increase of about 48%, for the nine months ended September 30, 2011 as compared to the nine monthsended September 30, 2010. During these respective periods, however, our oil and natural gas productionincreased 93% from 6.0 Bcfe to 11.6 Bcfe. As a result, our lease operating expenses per unit of productiondecreased by 22% to $0.49 per Mcfe for the nine months ended September 30, 2011 as compared to $0.63per Mcfe for the nine months ended September 30, 2010. During the first nine months of 2011, thepercentage of our production attributed to the Haynesville shale continued to increase. The unit leaseoperating costs associated with the Haynesville production are much less than those associated with ourCotton Valley natural gas production, primarily due to the greater salt water disposal costs associated withthe Cotton Valley production.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expensesincreased by $11.6 million to $22.6 million, or an increase of about 107%, for the nine months endedSeptember 30, 2011 as compared to the nine months ended September 30, 2010. The increase in ourdepletion, depreciation and amortization expenses was due primarily to an increase of approximately 93%in our oil and natural gas production from 6.0 Bcfe to 11.6 Bcfe during the respective time periods. Aportion of this increase was also due to a 7% increase in our depletion, depreciation and amortizationexpenses on a unit-of-production basis from $1.82 per Mcfe for the nine months ended September 30, 2010to $1.95 per Mcfe for the nine months ended September 30, 2011. This increase reflects increases in drillingand completion costs for wells drilled to the Haynesville shale during the past year. This increase was alsodue, in part, to higher finding and development costs on a per Mcfe basis associated with our initial wellsdrilled and completed in the Eagle Ford shale.

Accretion of asset retirement obligations. Our accretion of asset retirement obligations expensesincreased by approximately $51,000 to approximately $158,000, or an increase of about 48%, for the ninemonths ended September 30, 2011 as compared to the nine months ended September 30, 2010. The increasein our accretion of asset retirement obligations was due primarily to the addition of new wells through ourdrilling of operated wells and our participation in the drilling of non-operated wells, although, on the whole,this item is an insignificant component of our overall expenses.

Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gasproperties on the balance sheet resulting from the full-cost ceiling limitation was recorded at September 30,2010. At March 31, 2011, the net capitalized costs of our oil and natural gas properties less related deferredincome taxes exceeded the cost center ceiling by $23.0 million. As a result, we recorded an impairmentcharge of $35.7 million to the net capitalized costs of our oil and natural gas properties and a deferredincome tax credit of $12.7 million, which is also reflected in our expenses for the nine months endedSeptember 30, 2011.

General and administrative. Our general and administrative expenses increased by $2.6 million to $9.4million, or an increase of about 38%, for the nine months ended September 30, 2011 as compared to thenine months ended September 30, 2010. The increase in our general and administrative expenses was due

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primarily to increased cash and non-cash compensation expenses and increased accounting and legalexpenses for the nine months ended September 30, 2011 as compared to the nine months endedSeptember 30, 2010. As a result of our increased oil and natural gas production, however, our general andadministrative expenses decreased by 28% on a unit-of-production basis to $0.81 per Mcfe for the ninemonths ended September 30, 2011 as compared to $1.13 per Mcfe for the nine months ended September 30,2010.

Net gain (loss) on asset sales and inventory impairment. We did not incur gains or losses on asset salesand inventory impairment during the nine months ended September 30, 2011 or during the nine monthsended September 30, 2010.

Interest expense. At September 30, 2011, we had borrowed $85.0 million under our credit agreement,including a term loan of $25.0 million, to finance a portion of our working capital requirements and capitalexpenditures and had incurred total interest expense of approximately $1.2 million. We capitalized$756,000 of our interest expense on certain qualifying projects for the nine months ended September 30,2011 and expensed the remaining $461,000 to operations. At September 30, 2011, the interest rate on theterm loan was approximately 5.3% and the interest rate on the other outstanding borrowings wasapproximately 2.2%. We had no borrowings under the credit agreement at September 30, 2010 and, as aresult, we incurred no interest expense for the nine months ended September 30, 2010.

Interest and other income. Our interest and other income decreased by approximately $52,000 toapproximately $248,000, or a decrease of about 17%, for the nine months ended September 30, 2011 ascompared to the nine months ended September 30, 2010. The decrease in our interest and other income wasdue primarily to a significant decrease in the average balances of our cash and cash equivalents andcertificates of deposit on which we received interest income between the two periods. Our cash and cashequivalents and certificates of deposit decreased to approximately $9.9 million at September 30, 2011 fromapproximately $46.0 million at September 30, 2010, as we used cash to acquire additional leasehold acreagein the Eagle Ford shale play in south Texas and in the core area of the Haynesville shale play in northwestLouisiana and to fund our operated and non-operated drilling and completion activities in both areas.

Total income tax provision (benefit). We recorded a total income tax benefit of approximately $7.0million for the nine months ended September 30, 2011 as compared to a total income tax provision ofapproximately $4.0 million for the nine months ended September 30, 2010. The total income tax benefit forthe nine months ended September 30, 2011 reflected deferred income taxes almost entirely, with theexception of a state of Louisiana income tax refund of approximately $46,000 recorded during this period.At March 31, 2011, the net capitalized costs of our oil and natural gas properties less related deferredincome taxes exceeded the cost center ceiling by $23.0 million. As a result, we recorded an impairmentcharge of $35.7 million to the net capitalized costs of our oil and natural gas properties and a deferredincome tax credit of $12.7 million. This deferred income tax credit exceeded our deferred tax liabilities atMarch 31, 2011, and as a result, we reduced our net deferred tax liabilities by $6.9 million and established anet valuation allowance due to uncertainties regarding the future realization of our deferred tax assets. Weretained a net valuation allowance in the amount of approximately $0.8 million at September 30, 2011. Wewill continue to assess the valuation allowance on a periodic basis and to the extent we determine that theallowance is no longer required, the tax benefit of the remaining deferred tax assets will be recognized inthe future. The total income tax provision for the nine months ended September 30, 2010 included adeferred income tax provision of approximately $5.4 million and a current income tax benefit ofapproximately $1.4 million, which was attributable to a refund of U.S. federal income taxes received by us.For the nine months ended September 30, 2010, the deferred income tax provision was consistent with our

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income before income taxes, which included approximately $5.8 million in unrealized hedging gains. Wehad a net loss for the nine months ended September 30, 2011, and our effective tax rate for the nine monthsended September 30, 2010 was 35.42%.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Production taxes and marketing. Our production taxes and marketing expenses increased by$0.9 million to $2.0 million, or an increase of about 84%, for the year ended December 31, 2010 ascompared to the year ended December 31, 2009. The increase in our production taxes and marketingexpenses was due primarily to the increase in our oil and natural gas revenues from $19.0 million to$34.0 million, or an increase of about 79%, during the respective time periods. On a unit-of-productionbasis, our production taxes and marketing expenses remained relatively constant year-over-year,increasing to $0.23 per Mcfe for the year ended December 31, 2010 from $0.22 per Mcfe for the yearended December 31, 2009.

Lease operating expenses. Our lease operating expenses increased by $0.6 million to $5.3 million, oran increase of about 12%, for the year ended December 31, 2010 as compared to the year endedDecember 31, 2009. During these respective periods, however, our oil and natural gas production increased72% to 8.6 Bcfe from 5.0 Bcfe. As a result, our lease operating expenses per unit of production decreasedby 35% to $0.61 per Mcfe for the year ended December 31, 2010 as compared to $0.94 per Mcfe for theyear ended December 31, 2009. In 2010, the percentage of our production attributed to the Haynesvilleshale continued to increase. The unit lease operating costs associated with the Haynesville production aremuch less than those associated with our Cotton Valley natural gas production, primarily due to the greatersalt water disposal costs associated with the Cotton Valley production.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expensesincreased by $4.9 million to $15.6 million, or an increase of about 45%, for the year ended December 31,2010 as compared to the year ended December 31, 2009. The increase in our depletion, depreciation andamortization expenses was due primarily to the increase in our natural gas production to 8.6 Bcfe from 5.0Bcfe during the respective time periods. The finding and development costs associated with our Haynesvilleshale reserves have been less than finding and development costs associated with our reserves producingfrom the Cotton Valley and other formations. As a result, our depletion, depreciation and amortizationexpenses on a unit-of-production basis have continued to decrease as our Haynesville production hasincreased; these expenses decreased to $1.81 per Mcfe during the year ended December 31, 2010 from$2.15 per Mcfe during the year ended December 31, 2009.

Accretion of asset retirement obligations. Our accretion of asset retirement obligations expensesincreased by approximately $18,000 to approximately $155,000, or an increase of about 13%, for the yearended December 31, 2010 as compared to the year ended December 31, 2009. The increase in our accretionof asset retirement obligations was due primarily to the addition of new wells through our drilling ofoperated wells and our participation in the drilling of non-operated wells.

Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gasproperties on the balance sheet resulting from the full-cost ceiling limitation was recorded at December 31,2010. At December 31, 2009, the net capitalized costs of our oil and natural gas properties less relateddeferred income taxes exceeded the cost center ceiling by $16.3 million. As a result, we recorded animpairment charge of $25.2 million to the net capitalized costs of our oil and natural gas properties and adeferred income tax credit of $8.9 million. A corresponding charge of $25.2 million was also recorded tothe consolidated statement of operations for the year ended December 31, 2009.

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General and administrative. Our general and administrative expenses increased by $2.6 million to $9.7million, or an increase of about 36%, for the year ended December 31, 2010 as compared to the year endedDecember 31, 2009. Approximately $1.0 million of this increase was due to legal and other due diligencefees resulting from an unsuccessful effort to acquire oil and natural gas producing properties and associatedacreage. The remainder of the increase was due primarily to increased compensation expenses resultingfrom both increased salaries and retention and performance bonuses paid to certain employees during theyear ended December 31, 2010. As a result of our increased oil and natural gas production, however, ourgeneral and administrative expenses decreased by 20% on a unit-of-production basis to $1.13 per Mcfe forthe year ended December 31, 2010 as compared to $1.42 per Mcfe for the year ended December 31, 2009.

Net gain (loss) on asset sales and inventory impairment. During the year ended December 31, 2010,we wrote off the Boise South Pipeline asset in Orange County, Texas and recognized a net loss of $173,690.We also recognized an impairment of $50,000 to some of our equipment held in inventory following adetermination that the market value of the equipment, consisting primarily of drilling rig parts, was less thanthe cost. During the year ended December 31, 2009, we recognized impairments to these drilling rig partsand tubular goods held in inventory and sold rod parts held in inventory, recognizing a net loss of $0.4million.

Interest expense. In December 2010, we borrowed $25.0 million under our revolving credit agreementto finance a portion of our working capital requirements and capital expenditures. At December 31, 2010,the interest rate on the outstanding borrowings was approximately 1.6%. We had no borrowings under thecredit agreement in 2009, and as a result, we incurred no interest expense for the year ended December 31,2009.

Interest and other income. Our interest and other income decreased by approximately $0.4 million toapproximately $0.4 million, or a decrease of about 53%, for the year ended December 31, 2010 as comparedto the year ended December 31, 2009. The decrease in our interest and other income was due primarily to adecrease in the average balances of our cash and cash equivalents and certificates of deposit on which wereceive interest income during the year ended December 31, 2010 as compared to the year endedDecember 31, 2009. Our cash and cash equivalents and certificates of deposit decreased to $23.4 million atDecember 31, 2010 from $119.9 million at December 31, 2009, as we used cash during this periodprimarily to acquire additional leasehold acreage in the Eagle Ford shale play in south Texas and in the corearea of the Haynesville shale play in northwest Louisiana and to fund our operated and non-operated drillingand completion activities in both areas.

Total income tax provision (benefit). We recorded a total income tax provision of approximately $3.5million for the year ended December 31, 2010 as compared to a total income tax benefit of approximately$9.9 million recorded for the year ended December 31, 2009. For the year ended December 31, 2010, werecorded a current income tax benefit of approximately $1.4 million, which was attributable to a refund ofU.S federal income taxes received by us, and we also recorded a deferred income tax provision of $4.9million consistent with the increase in our income before income taxes for that year. For the year endedDecember 31, 2009, we recorded a current income tax benefit of approximately $2.3 million, primarilyattributable to a net refund of U.S. federal income taxes and a refund of income taxes from the state ofLouisiana. We also recorded a deferred income tax benefit of approximately $7.6 million, primarilyattributable to the full-cost ceiling impairment recorded in 2009. Our effective tax rate for the year endedDecember 31, 2010 was 35.57%, and we had a net loss for the year ended December 31, 2009.

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Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Production taxes and marketing. Our production taxes and marketing expenses decreasedapproximately $0.6 million to $1.1 million, or a decrease of about 34%, during the year endedDecember 31, 2009 as compared to the year ended December 31, 2008. The decrease in our productiontaxes and marketing expenses was due primarily to a decrease of about 38% in our oil and natural gasrevenues to $19.0 million for the year ended December 31, 2009 from $30.6 million for the year endedDecember 31, 2008. Because our production increased 51% from 3.3 Bcfe to 5.0 Bcfe during theserespective periods, our production taxes and marketing expenses on a unit-of-production basis decreased to$0.22 per Mcfe during the year ended December 31, 2009 from $0.50 per Mcfe for the year endedDecember 31, 2008.

Lease operating expenses. Our lease operating expenses increased approximately $58,000 to $4.7million, or an increase of about 1%, during the year ended December 31, 2009 as compared to the yearended December 31, 2008. During these respective periods, however, our production increased 51%, from3.3 Bcfe to 5.0 Bcfe. We began producing natural gas from the Haynesville shale in June 2009 andadditional Haynesville wells began producing with corresponding sales during the latter part of 2009.Despite this production growth in 2009, our lease operating expenses increased only slightly due to the factthat the unit lease operating costs associated with the Haynesville production were much less than thoseassociated with the Cotton Valley production, which made up the majority of our production during 2008.This is primarily due to the greater salt water disposal costs associated with the Cotton Valley production.As a result, our unit lease operating costs decreased to $0.94 per Mcfe during the year ended December 31,2009 from $1.41 per Mcfe during the year ended December 31, 2008, or a decrease of about 33%.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expensesdecreased $1.4 million to $10.7 million, or a decrease of about 11%, during the year ended December 31,2009 as compared to the year ended December 31, 2008. Our depletion, depreciation and amortizationexpenses decreased despite the fact that our production grew 51% from 3.3 Bcfe to 5.0 Bcfe during theserespective periods. This decrease was due to the fact that the finding and development costs associated withour Haynesville shale production have been less than the finding and development costs associated with ourproduction from the Cotton Valley and other formations. As a result, our depletion, depreciation andamortization expenses on a unit-of-production basis decreased to $2.15 per Mcfe for the year endedDecember 31, 2009 from $3.67 per Mcfe for the year ended December 31, 2008.

Accretion of asset retirement obligations. Our accretion of asset retirement obligations expensesincreased approximately $46,000 to $137,000, or an increase of about 51%, during the year endedDecember 31, 2009 as compared to the year ended December 31, 2008. The increase in our accretion ofasset retirement obligations was due primarily to the addition of new wells through our drilling of operatedwells and our participation in the drilling of non-operated wells.

Full-cost ceiling impairment. At December 31, 2009, the net capitalized costs of our oil and natural gasproperties less related deferred income taxes exceeded the cost center ceiling by $16.3 million. As a result,we recorded an impairment charge of $25.2 million to the net capitalized costs of our oil and natural gasproperties and a deferred income tax credit of $8.9 million. A corresponding charge of $25.2 million wasalso recorded to the consolidated statement of operations for the year ended December 31, 2009. AtDecember 31, 2008, the net capitalized costs of our oil and natural gas properties less related deferredincome taxes exceeded the cost center ceiling by $14.3 million. As a result, we recorded an impairmentcharge of $22.2 million to the net capitalized costs of our oil and natural gas properties and a deferred

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income tax credit of $7.9 million. A corresponding charge of $22.2 million was also recorded in theconsolidated statement of operations for the year ended December 31, 2008.

General and administrative. Our general and administrative expenses decreased by $1.1 million to$7.1 million, or a decrease of about 14%, for the year ended December 31, 2009 as compared to the yearended December 31, 2008. The decrease in our general and administrative expenses was due primarily to adecrease in compensation expenses between the respective periods. In July 2008, we paid a special cashperformance bonus of approximately $1.7 million to eligible employees in recognition of the significantincrease in the value of our assets resulting from the sale of a portion of our Haynesville shale explorationand development rights in northwest Louisiana. We did not make any such extraordinary cash bonuspayments to our employees during the year ended December 31, 2009; however, the decrease in bonuscompensation in 2009 as compared to 2008 was offset to some degree by additional compensation expenseassociated with the hiring of new staff and the general increase in the costs to conduct our business duringthe year ended December 31, 2009. As a result of our increased oil and natural gas production, however, ourgeneral and administrative expenses decreased by 43% on a unit-of-production basis to $1.42 per Mcfe forthe year ended December 31, 2009 as compared to $2.50 per Mcfe for the year ended December 31, 2008.

Net gain (loss) on asset sales and inventory impairment. Our net gain (loss) on asset sales andinventory impairment decreased by $137.4 million to a net loss of approximately $0.4 million for the yearended December 31, 2009 as compared to a net gain of $137.0 million for the year ended December 31,2008. During the year ended December 31, 2009, we recognized impairments to drilling rig parts andtubular goods held in inventory and sold rod parts held in inventory, recognizing a net loss of $0.4 million.During the year ended December 31, 2008, we sold a portion of our Haynesville shale exploration anddevelopment rights in northwest Louisiana to a subsidiary of Chesapeake Energy Corporation andrecognized a gain of $137.0 million on the sale. We also recognized a loss of about $44,000 on the sale oftubular goods held in inventory during 2008.

Interest expense. We had no borrowings under our credit agreement in 2009 or 2008. As a result, wehad no interest expense for the years ended December 31, 2009 and 2008.

Interest and other income. Our interest and other income expenses decreased by $2.2 million to$0.8 million, or a decrease of about 74%, for the year ended December 31, 2009 as compared to the yearended December 31, 2008. The decrease in our interest and other income expenses was due primarily to adecrease in the average balances of our cash and cash equivalents and certificates of deposit on which wereceive interest income during the respective periods. Our cash and cash equivalents and certificates of depositdecreased to $119.9 million at December 31, 2009 from $171.6 million at December 31, 2008, as we usedcash during this period primarily to acquire additional leasehold acreage in the core area of the Haynesvilleshale play in northwest Louisiana and to fund our operated and non-operated drilling and completion activities.

Total income tax provision (benefit). We recorded a total income tax benefit of approximately $9.9million for the year ended December 31, 2009 as compared to a total income tax provision of approximately$20.0 million for the year ended December 31, 2008. For the year ended December 31, 2009, we recorded acurrent income tax benefit of approximately $2.3 million, primarily attributable to a net refund of U.S.federal income taxes and a refund of income taxes from the state of Louisiana. We also recorded a deferredincome tax benefit of approximately $7.6 million, primarily attributable to the full-cost ceiling impairmentrecorded in 2009. For the year ended December 31, 2008, we recorded a current income tax provision ofapproximately $10.4 million which reflects the payment of $9.4 million in U.S. federal alternative minimum

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tax and approximately $1.0 million in income tax to the state of Louisiana. The alternative minimum taxpayment resulted from exhausting our alternative minimum tax net operating loss due to the gain realizedfrom the sale of certain of our Haynesville shale assets. See “Business — Other Significant Prior Events.”We also recorded a deferred income tax provision of approximately $9.6 million, reflecting both the largeincrease in our income before income taxes for the year, partially offset by the deferred income tax benefitattributable to the full-cost ceiling impairment recorded in 2008, and by the reversal of a previouslyestablished valuation allowance of approximately $24.7 million. We had a net loss for the year endedDecember 31, 2009, and our effective tax rate for the year ended December 31, 2008 was 16.16%.

Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from private investors, ourcash flows from operations, borrowings under our credit agreement and the proceeds from a significant saleof a portion of our assets in 2008. See “Business — Other Significant Prior Events.” Our primary use ofcapital has been for the acquisition, exploration and development of oil and natural gas properties. Wecontinually evaluate potential capital sources, including equity and debt financings, in order to meet ourplanned capital expenditures and liquidity requirements. Our future success in growing proved reserves andproduction will be highly dependent on our ability to access outside sources of capital. At September 30,2011, we had cash and certificates of deposits totaling approximately $9.9 million.

In December 2011, we amended and restated our senior secured revolving credit agreement for whichComerica Bank serves as administrative agent. This amendment increased the maximum facility amountfrom $150 million to $400 million. Borrowings are limited to the lesser of $400 million or the borrowingbase. At January 27, 2012, the borrowing base was $125 million, and we had $123.0 million of outstandingindebtedness. There were $1.3 million in outstanding letters of credit at September 30, 2011. Following thisoffering and after application of the net proceeds, our borrowing base will be $100 million until asubsequent redetermination, which we expect will be done following the completion of our December 31,2011 reserves report. The new amended credit agreement matures in December 2016. At January 27, 2012,all borrowings under our credit agreement bore interest at a variable rate of 3.25% plus a Eurodollar-basedrate per annum, which equated to approximately 3.5% per annum.

We previously entered into the credit agreement in March 2008 and amended and restated it for thefirst time in May 2011. At September 30, 2011, the agreement provided for a borrowing base of $80.0million and our outstanding revolving borrowings under the credit agreement bore interest at the rate of2.2%. In addition to our revolving borrowings under the credit agreement, in May 2011, we borrowed$25 million in a term loan pursuant to the credit agreement. The term loan was due and payable onDecember 31, 2011, and there was no penalty for prepayment. The term loan bore interest at an annual rateof 5% plus a Eurodollar-based rate, which equated to approximately 5.3% at September 30, 2011. This termloan was refinanced by revolving borrowings under the amended and restated credit agreement in December2011. For more information regarding our amended and restated credit agreement, see “— CreditAgreement.”

We actively review acquisition opportunities on an ongoing basis. While we believe the net proceedswe receive from this offering, together with our cash flows and future potential borrowings under our creditagreement, will be adequate to fund our capital expenditure requirements and any acquisitions of interestsand acreage for 2012, funding for future acquisitions of interests and acreage or our future capitalexpenditure requirements for 2013 and subsequent years may require additional sources of financing, whichmay not be available. As a result of our anticipated increases in production and reserves, we expect to have

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a sufficient increase in our cash flows from operations during the year ending December 31, 2012, ascompared to our cash flows from operations in prior periods, as well as a sufficient increase in theborrowing base under our credit agreement to help fund our 2012 capital expenditure budget. A majority ofour anticipated increase in cash flows during the year ending December 31, 2012 is expected to come fromour exploration activities on unproved properties at September 30, 2011 in the Eagle Ford shale playassuming such exploration activities are successful. These anticipated increases in our cash flows fromoperations are based upon current oil and natural gas prices and the hedges we currently have in place. Ifour exploration activities result in less cash flows than anticipated, we may seek additional sources ofcapital, including through borrowings under our credit agreement (assuming availability under ourborrowing base) or from the issuance of additional equity or debt securities. In addition, we may modify ourplanned capital expenditure budget for 2012 accordingly. Exploration activities are subject to a number ofrisks and uncertainties that could impact our ability to sufficiently increase our reserves, cash flows fromoperations and borrowing base under our credit agreement. See “Risk Factors — Our Exploration,Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed OurCash Flows From Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capitalon Satisfactory Terms, Which Could Adversely Affect Our Future Growth” and “— Drilling for andProducing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with ManyUncertainties That Could Adversely Affect Our Business.” We anticipate that we may need to access futureborrowings under our credit agreement within 30 days following completion of this offering to fund aportion of our 2012 capital expenditure requirements in excess of amounts available from our cash flowsand the net proceeds of this offering. See “Use of Proceeds.”

Our cash flows for the years ended December 31, 2010, 2009 and 2008 and the nine months endedSeptember 30, 2011 and 2010, are presented below:

Year EndedDecember 31,


2010 2009 2008 2011 2010

(In thousands) (Unaudited) (Unaudited)Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . $ 27,273 $ 1,791 $ 25,851 $ 34,443 $ 21,390Net cash provided by (used in) investing activities . . . . . . . . . . . . . . . . . (147,334) (49,415) 115,481 (107,772) (78,718)Net cash provided by (used in) financing activities . . . . . . . . . . . . . . . . . 36,891 1,086 419 60,037 (8,284)

Net change in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . $ (83,170) $(46,538) $141,751 $ (13,292) $(65,612)

Cash Flows Provided by Operating Activities

Net cash provided by operating activities increased by $13.0 million to $34.4 million for the ninemonths ended September 30, 2011 as compared to net cash provided by operating activities of $21.4 millionfor the nine months ended September 30, 2010. Net cash provided by oil and natural gas operationsincreased significantly to $37.1 million for the nine months ended September 30, 2011 from $18.5 millionfor the nine months ended September 30, 2010. This increase reflects primarily the 93% increase in our oiland natural gas production to 11.6 Bcfe from 6.0 Bcfe between the respective periods. This increase in cashflows provided by oil and natural gas operations was offset partially by changes in our operating assets andliabilities totaling approximately $5.6 million between September 30, 2010 and September 30, 2011. Ouraccounts payable and accrued liabilities increased to approximately $21.4 million at September 30, 2011from approximately $15.2 million at September 30, 2010 due to our increased operating activity in southTexas. Our accounts receivable increased to $14.1 million at September 30, 2011 as compared to $7.5million at September 30, 2010 due primarily to the increase in our oil and natural gas production andassociated revenues.

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Net cash provided by operating activities increased by $25.5 million to $27.3 million for the yearended December 31, 2010 as compared to net cash provided by operating activities of $1.8 million for theyear ended December 31, 2009. The increase in cash flows provided by operations reflects an increase inour production to 8.6 Bcfe from 5.0 Bcfe and an increase in the average prices we received for oil andnatural gas production for the year ended December 31, 2010 as compared to the year ended December 31,2009. Our accounts payable and accrued liabilities were approximately $26.8 million at December 31, 2010as a result of operated horizontal wells that we were drilling and/or completing in the Haynesville and EagleFord shale plays and in the Cotton Valley formation during the fourth quarter of 2010. Our accountspayable and accrued liabilities were $7.3 million at December 31, 2009 as we were drilling and completingonly one operated horizontal Haynesville shale well at that time.

Net cash provided by operating activities decreased by $24.1 million to $1.8 million for the year endedDecember 31, 2009 from $25.9 million for the year ended December 31, 2008. Although our productionincreased to 5.0 Bcfe for the year ended December 31, 2009 from 3.3 Bcfe for the year ended December 31,2008, the average prices we received for oil and natural gas declined sharply between the respective periods.Our accounts payable and accrued liabilities were approximately $7.3 million at December 31, 2009 as wewere drilling and/or completing only one operated horizontal Haynesville shale well at that time. Ouraccounts payable and accrued liabilities were approximately $25.2 million at December 31, 2008 as wewere drilling and/or completing both operated vertical Cotton Valley wells and our first operated horizontalwells in the Haynesville shale play at that time.

Our operating cash flows are sensitive to a number of variables, including changes in our productionand volatility of oil and natural gas prices between reporting periods. Regional and worldwide economicactivity, weather, infrastructure capacity to reach markets and other variable factors significantly impact theprices of oil and natural gas. These factors are beyond our control and are difficult to predict. For additionalinformation on the impact of changing prices on our financial position, see “— Quantitative and QualitativeDisclosures About Market Risk” below. See also “Risk Factors — Our success is dependent on the prices ofoil and natural gas. Low oil or natural gas prices and the substantial volatility in these prices may adverselyaffect our financial condition and our ability to meet our capital expenditure requirements and financialobligations.”

Cash Flows Provided by (Used in) Investing Activities

Net cash used in investing activities increased by $29.1 million to $107.8 million for the nine monthsended September 30, 2011 from $78.7 million for the nine months ended September 30, 2010. This increasein net cash used in investing activities reflected primarily an increase of $18.7 million in our oil and naturalgas properties capital expenditures for the nine months ended September 30, 2011 as compared to the ninemonths ended September 30, 2010. The increased oil and natural gas properties capital expenditures for thenine months ended September 30, 2011 were primarily due to increased expenditures associated with ouroperated and non-operated drilling and completion activities in the Eagle Ford and Haynesville plays andour acreage acquisition in Karnes, DeWitt, Wilson and Gonzales Counties, Texas, as compared to the ninemonths ended September 30, 2010.

Net cash used in investing activities increased by $97.9 million to $147.3 million for the year endedDecember 31, 2010 from $49.4 million for the year ended December 31, 2009. This increase in net cashused in investing activities reflects primarily an increase of $104.8 million in our oil and natural gasproperties capital expenditures for the year ended December 31, 2010 as compared to the year endedDecember 31, 2009. The increased oil and natural gas properties capital expenditures for the year endedDecember 31, 2010 are due to the acquisition of leasehold acreage in the Eagle Ford shale play and the

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acquisition of additional leasehold acreage in the Haynesville shale play, as well as expenditures associatedwith our operated and non-operated drilling and completion activities in both plays, as compared to the yearended December 31, 2009.

Net cash used in investing activities was $49.4 million for the year ended December 31, 2009 ascompared to net cash provided by investing activities of $115.5 million for the year ended December 31,2008. This decrease of $164.9 million in net cash provided by investing activities between the respectiveperiods reflects primarily the proceeds received from the sale of a portion of our Haynesville rights innorthwest Louisiana to a subsidiary of Chesapeake Energy Corporation in 2008. In addition, our oil andnatural gas properties capital expenditures decreased by $49.9 million between the two periods owing to adecrease in our operated drilling activity and related capital expenditures in 2009.

Expenditures for the acquisition, exploration and development of oil and natural gas properties are theprimary use of our capital resources. We anticipate investing $313.0 million in capital for acquisition,exploration and development activities in 2012 as follows:

Amount(in millions)

Exploration and development drilling and associated infrastructure . . . . . . . . . . . . . . . . . . . . . . . . . . $284.5Leasehold acquisition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24.0Other capital expenditures, 2-D and 3-D seismic data and recompletions of existing wells . . . . . . . . 4.5

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $313.0

For further information regarding our anticipated capital expenditure budget in 2012, see “Business—Overview.”

Our 2012 capital expenditures may be adjusted as business conditions warrant. The amount, timing andallocation of capital expenditures is largely discretionary and within our control. If oil or natural gas pricesdecline or costs increase significantly, we could defer a significant portion of our anticipated capitalexpenditures until later periods to conserve cash or to focus on those projects that we believe have thehighest expected returns and potential to generate near-term cash flows. We routinely monitor and adjustour capital expenditures in response to changes in prices, availability of financing, drilling, completion andacquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success orlack of success in our exploration and development activities, contractual obligations and other factors bothwithin and outside our control.

Cash Flows Provided by (Used in) Financing Activities

Net cash provided by financing activities was $60.0 million for the nine months ended September 30,2011 as compared to net cash used in financing activities of $8.3 million for the nine months endedSeptember 30, 2010. The net cash provided by financing activities for the nine months ended September 30,2011 was due almost entirely to additional borrowings of $60.0 million under our credit agreement to fundour working capital requirements as well as our acquisition of acreage prospective for the Eagle Ford shaleplay in Karnes, DeWitt, Wilson and Gonzales Counties, Texas. In addition, in January 2011, we sold 53,772shares of our Class A common stock in a private placement and received net proceeds of approximately$0.6 million. The net cash used in financing activities of $8.3 million for the nine months endedSeptember 30, 2010 reflected primarily our repurchase of 1,000,000 shares of Class A common stock inApril 2010 at $9.00 per share for a total of $9.0 million.

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Net cash provided by financing activities was $36.9 million for the year ended December 31, 2010 ascompared to net cash provided by financing activities of $1.1 million for the year ended December 31, 2009.For the year ended December 31, 2010, the most significant financing activities occurred in the fourthquarter of 2010. During that time, we sold approximately 1.9 million shares of our Class A common stock ina private placement and received net proceeds of approximately $21.0 million, and we borrowed$25.0 million under our credit agreement. In addition, in April 2010, we repurchased 1,000,000 shares ofClass A common stock from five shareholders, all advised by Wellington Management Company, for a totalof $9.0 million. We also received proceeds of approximately $2.0 million from the periodic exercise ofstock options for the year ended December 31, 2010. For the year ended December 31, 2009, the mostsignificant financing activities occurred in April 2009 when we repurchased approximately 5.4 millionshares of Class A common stock from Gandhara Capital, one of our largest shareholders at the time, for atotal of $27.1 million and in May through September 2009 when we sold approximately 5.0 million sharesof Class A common stock in a private placement and received net proceeds of approximately $28.0 million.We also received proceeds of approximately $1.3 million from the periodic exercise of stock options for theyear ended December 31, 2009.

Net cash provided by financing activities was $1.1 million for the year ended December 31, 2009 ascompared to $0.4 million for the year ended December 31, 2008. For the year ended December 31, 2009,the most significant financing activities occurred in April 2009 when we repurchased approximately5.4 million shares of Class A common stock from Gandhara Capital, one of our largest shareholders at thetime, at $5.00 per share for a total of $27.1 million and in May through September 2009 when we soldapproximately 5.0 million shares of Class A common stock in a private placement and received netproceeds of approximately $28.0 million. We also received proceeds of approximately $1.3 million from theperiodic exercise of stock options for the year ended December 31, 2009. For the year ended December 31,2008, the most significant financing activities were the periodic exercise of stock options for which wereceived aggregate net proceeds of approximately $1.0 million.

Credit Agreement

In December 2011, we amended and restated our senior secured revolving credit agreement for whichComerica Bank serves as administrative agent. Among other things, this amendment increased the size ofthe facility and extended the term until December 2016. MRC Energy Company is the borrower under thenew amended and restated credit agreement. Borrowings under the credit agreement are secured bymortgages on substantially all of our oil and natural gas properties and by the equity interests of all of MRCEnergy Company’s wholly owned subsidiaries, which are also guarantors. In addition, all obligations underthe credit agreement are guaranteed by Matador Resources Company, the parent corporation. Variouscommodity hedging agreements and interest rate agreements with one of the lenders under the creditagreement (or an affiliate thereof) are also secured by the collateral and guaranteed by the subsidiaries ofMRC Energy Company.

The amount of the borrowings under our amended and restated credit agreement is limited to the lesserof $400.0 million or the borrowing base, which is determined semi-annually as of May 1 and November 1by the lenders based primarily on the estimated value of our existing and future acquired oil and gasreserves, but also on external factors, such as the lenders’ lending policies and the lenders’ estimates offuture oil and natural gas prices, over which we have no control. At January 27, 2012, the borrowing basewas $125.0 million. After repayment of the then outstanding borrowings under our credit agreement withthe net proceeds of this offering, the borrowing base will be reduced to $100.0 million until any subsequentredetermination of the borrowing base under the agreement, which we expect will be done following the

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completion of our December 31, 2011 reserves report. Both Comerica Bank and we may each request anunscheduled redetermination of the borrowing base twice during the first year of the credit agreement andonce between scheduled determination dates thereafter. In the event of a borrowing base increase, we arerequired to pay a fee to the lenders, which will be determined by Comerica Bank based on marketconditions at the time of the borrowing base increase. Except as set forth in the following sentence, if theborrowing base were to be less than the outstanding borrowings under the credit agreement at any time, wewould be required to provide additional collateral satisfactory in nature and value to the lenders to increasethe borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installmentsover a period of six months. If, however, our outstanding borrowings under the credit agreement exceed$100.0 million on the earlier of December 31, 2012, the second business day following receipt by us of thenet cash proceeds from this offering, or the date on which we inform the lenders that the borrowing base isequal to $100.0 million, then we will be required to immediately repay such excess amount.

If we borrow funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of(i) the weighted average of rates used in overnight federal funds transactions with members of the FederalReserve System plus 1.0%, (ii) the prime rate for Comerica Bank then in effect or (iii) a daily adjusted LIBORrate plus 1.0% plus, in each case, an amount from 0.375% to 1.75% of such outstanding loan depending on thelevel of borrowings under the agreement. If we borrow funds as a Eurodollar loan, such borrowings will bearinterest at a rate equal to (i) the quotient obtained by dividing (A) the interest rate appearing on Page BBAM ofthe Bloomberg Financial Markets Information Service by (B) a percentage equal to 100% minus the maximumrate during such interest calculation period at which Comerica Bank is required to maintain reserves onEurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal ReserveSystem), plus (ii) an amount from 1.375% to 2.75% of such outstanding loan depending on the level ofborrowings under the agreement. The interest period for Eurodollar borrowings may be one, two, three or sixmonths as designated by us. A facility fee of 0.375% to 0.50%, depending on the amounts borrowed, is alsopaid quarterly in arrears. We include this facility fee in our interest rate calculations and related disclosures.

Key financial covenants under the credit agreement require us to maintain (1) a minimum current ratio,which is defined as consolidated total current assets (including the unused availability under the creditagreement) divided by consolidated total current liabilities, of 1.0 or greater, and (2) a debt to EBITDAratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of4.0 to 1.0 or less.

Subject to certain exceptions, our credit agreement contains various covenants that limit our, alongwith our subsidiaries’, ability to take certain actions, including, but not limited to, the following:

• incur indebtedness or grant liens on any of our assets;

• enter into commodity hedging agreements;

• declare or pay dividends, distributions or redemptions;

• merge or consolidate;

• make any loans or investments;

• engage in transactions with affiliates; and

• engage in certain asset dispositions, including a sale of all or substantially all of our assets.

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If an event of default exists under the credit agreement, the lenders will be able to accelerate thematurity of the credit agreement and exercise other rights and remedies. Events of default include, but arenot limited to, the following events:

• failure to pay any principal or interest on the notes or any reimbursement obligation under anyletter of credit when due or any fees or other amount within certain grace periods;

• failure to perform or otherwise comply with the covenants and obligations in the credit agreementor other loan documents, subject, in certain instances, to certain grace periods;

• bankruptcy or insolvency events involving us or our subsidiaries; and

• a change of control, as defined in the credit agreement.

We had no borrowings under the credit agreement at December 31, 2009 and 2008. In December 2010,the credit agreement was amended to increase the borrowing base to $55.0 million. At December 31, 2010,we had $25.0 million of outstanding borrowings and $50,000 in letters of credit issued pursuant to the creditagreement. At December 31, 2010, all borrowings under the credit agreement were Eurodollar loans, andthe interest rate on the outstanding borrowings was approximately 1.6%. We had an additional $325,000 inletters of credit secured by certificates of deposit at Comerica Bank at December 31, 2010.

We believe that we were in compliance with the terms of our credit agreement and with all our bankcovenants at December 31, 2010, 2009 and 2008. We obtained a written extension from Comerica Bankuntil July 15, 2011 to comply with a covenant under the credit agreement requiring submission of auditedfinancial statements within 120 days of the prior year end and the submission of quarterly financialstatements within 45 days of the prior quarter end. We submitted both sets of financial statements toComerica Bank prior to this deadline.

At September 30, 2011, the borrowing base available for revolving borrowings was $80.0 million, andwe had $60.0 million in revolving borrowings outstanding under the credit agreement, approximately $1.3million in outstanding letters of credit issued pursuant to the credit agreement and approximately $18.7million available for additional borrowings. At September 30, 2011, our outstanding revolving borrowingsbore interest at the rate of approximately 2.2%. Prior to the December 2011 amendment, the outstandingrevolving borrowings under our credit agreement were scheduled to mature in March 2013.

In addition to our revolving borrowings under our credit agreement, in May 2011, we borrowed $25.0million in a term loan pursuant to the credit agreement to help finance the acquisition of the Eagle Fordshale acreage from Orca ICI Development, JV in Karnes, DeWitt, Wilson and Gonzales Counties, Texas.The term loan was due and payable on December 31, 2011, and there was no penalty for prepayment. Theterm loan bore interest at an annual rate of 5% plus a Eurodollar-based rate, which equated to approximately5.3% at September 30, 2011, and while any principal and interest under the term loan was outstanding, therevolving borrowings under the credit agreement bore interest at the maximum annual rate of 1.875% plus aEurodollar-based rate which equated to approximately 2.2% at September 30, 2011. The term loan wasrefinanced by borrowings under the amended and restated credit agreement in December 2011. AtJanuary 27, 2012, the borrowing base available for revolving borrowings was $125.0 million, and we had$123.0 million in revolving borrowings outstanding under the credit agreement, excluding outstandingletters of credit. We intend to repay all then outstanding borrowings under our credit agreement with the netproceeds we receive from this offering. We anticipate that we may need to access future borrowings underour credit agreement within 30 days following completion of this offering to fund a portion of our 2012capital expenditure requirements in excess of amounts available from our cash flows and the net proceeds ofthis offering.

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Obligations and Commitments

We had the following material contractual obligations and commitments at September 30, 2011 exceptas indicated:

Payments Due by Period

TotalLess Than

1 Year 1 -3 Years 3 -5 YearsMore Than

5 Years

(in thousands)Contractual Obligations:

Revolving credit borrowings and term loan, including letters ofcredit(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 86,263 $26,263 $60,000 $ – $ –

Office lease . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,243 144 1,150 1,186 3,763Non-operated drilling commitments(2) . . . . . . . . . . . . . . . . . . . . 1,700 1,700 – – –Drilling rig contracts(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,100 5,100 – – –Geological and geophysical contracts(4) . . . . . . . . . . . . . . . . . . . 310 310 – – –Employee bonuses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,240 – 1,240 – –Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,305 332 461 957 2,555

Total contractual cash obligations . . . . . . . . . . . . . . . . . . . . . . . $105,161 $33,849 $62,851 $2,143 $6,318

(1) At September 30, 2011, we had $60.0 million in revolving borrowings outstanding under our credit agreement, approximately $1.3million in outstanding letters of credit issued pursuant to the credit agreement and $25.0 million outstanding under the term loan. Theterm loan was scheduled to mature on December 31, 2011, and our borrowings under our credit agreement were scheduled to mature inMarch 2013. All such amounts are now included as revolving borrowings under our credit agreement. These amounts do not includeestimated interest on the obligations, because our revolving borrowings had short-term interest periods, and we are unable to determinewhat our borrowing costs may be in future periods. We incurred $38.0 million in additional borrowings in November and December2011 and in January 2012 under our credit agreement to fund certain capital expenditures.

(2) At September 30, 2011, we had outstanding commitments to participate in the drilling and completion of various non-operated wells inthe Haynesville shale play. Our working interest in these wells varies from 0.03% to 0.4%, and most of these wells were in progress atSeptember 30, 2011. If all these wells are drilled and completed, we estimate that we will have a minimum outstanding aggregate capitalcommitment for our participation in these wells of approximately $1.7 million at September 30, 2011, which we expect to incur withinthe next 12 months.

(3) At September 30, 2011, we had entered into two drilling rig contracts to explore and develop our Eagle Ford acreage in south Texas. Thefirst rig began drilling operations on our acreage in September 2011 and the second rig began drilling operations on our acreage inNovember 2011. Both contracts are for a term of six months. Should we elect to terminate both contracts and if the drilling contractorwere unable to secure work for both rigs or if the drilling contractor were unable to secure work for both rigs at the same daily ratesbeing charged to us prior to the end of their respective contract terms, we would incur termination obligations for either or both rigs. Ourmaximum outstanding aggregate capital commitment on these contracts was approximately $5.1 million as of September 30, 2011.

(4) Includes fees pending for two 3-D seismic acquisition projects across our Eagle Ford acreage in south Texas and for core analysis to beprovided by a division of Core Laboratories, LP.

Critical accounting policies and estimates

We have outlined below certain accounting policies that are of particular importance to thepresentation of our financial condition and results of operations and require the application of significantjudgment or estimates by our management.

Basis of Presentation

The consolidated financial statements include the accounts of Matador Resources Company and itsfour wholly owned subsidiaries, Matador Production Company, Longwood Gathering and Disposal SystemsGP, Inc., MRC Permian Company and MRC Rockies Company, as well as the accounts of LongwoodGathering and Disposal Systems, LP (our consolidated financial statements for the years ended

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December 31, 2010, 2009 and 2008 reflect our organizational structure prior to the consummation of theholding company merger; see “Corporate Reorganization”). Our consolidated financial statements havebeen prepared in accordance with GAAP. Our operations are conducted in one segment, generally referredto as the exploration and production industry. All significant intercompany balances and transactions havebeen eliminated in consolidation.

Pursuant to the terms of the corporate reorganization that was completed on August 9, 2011, MatadorResources Company changed its corporate name to MRC Energy Company and Matador Holdco, Inc.changed its corporate name to Matador Resources Company. As a part of this reorganization, MRC EnergyCompany became a wholly owned subsidiary of Matador Resources Company. Our unaudited condensedconsolidated financial statements at September 30, 2011 include the accounts of Matador ResourcesCompany and its wholly owned subsidiary, MRC Energy Company, as well as the accounts of MRC EnergyCompany’s four wholly owned subsidiaries, Matador Production Company, Longwood Gathering andDisposal Systems GP, Inc., MRC Permian Company and MRC Rockies Company, and the accounts ofLongwood Gathering and Disposal Systems, LP.

Use of Estimates

The discussion and analysis of our financial condition and results of operations are based upon ourconsolidated financial statements. The preparation of our financial statements requires us to make estimatesand assumptions that affect the amounts reported in the financial statements and accompanying notes. Theseestimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of thefinancial statements and the reported amounts of revenues and expenses during the reporting period. Weevaluate our estimates and assumptions on a regular basis. We base our estimates on historical experienceand various assumptions that are believed to be reasonable under the circumstances, the results of whichform the basis for making judgments about the carrying values of assets and liabilities that are not readilyapparent from other sources. While we believe our estimates are reasonable, changes in facts andassumptions or the discovery of new information may result in revised estimates. Actual results could differfrom these estimates and assumptions used in preparation of our consolidated financial statements.

Our consolidated financial statements are based on a number of significant estimates. These includeestimates of oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuationof derivative financial instruments and oil and natural gas reserves. The estimates of oil and natural gasreserves quantities and future net cash flows are the basis for the calculations of depletion and impairmentof oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals.Our oil and natural gas reserves estimates, which are inherently imprecise and based upon many factorsbeyond our control, are prepared by our engineering staff in accordance with guidelines established by theSEC and then audited for their reasonableness by independent petroleum engineers, except for certaininterim periods as noted.

Accounts Receivable

We sell our oil and natural gas production to various purchasers. Due to the nature of the markets foroil and natural gas, we do not believe that the loss of any one purchaser would significantly impactoperations. In addition, we may participate with industry partners in the drilling, completion and operationof oil and natural gas wells. Substantially all of our accounts receivable are due from either purchasers of oiland natural gas or participants in oil and natural gas wells for which we serve as the operator. Accounts

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receivable are due within 30 to 45 days of the production or billing date and are stated at amounts due frompurchasers and industry partners.

We review our need for an allowance for doubtful accounts on a periodic basis, and determine theallowance, if any, by considering the length of time past due, previous loss history, future net revenues ofthe debtor’s ownership interest in oil and natural gas properties we operate and the debtor’s ability to pay itsobligations, among other things. We have no allowance for doubtful accounts related to our accountsreceivable for any reporting period presented.

Property and Equipment

We use the full-cost method of accounting for our investments in oil and natural gas properties. Underthis method of accounting, all costs associated with the acquisition, exploration and development of oil andnatural gas properties and reserves, including unproved and unevaluated property costs, are capitalized asincurred and accumulated in a single cost center representing our activities, which are undertakenexclusively in the United States. Such costs include lease acquisition costs, geological and geophysicalexpenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productivewells, capitalized interest on qualifying projects and general and administrative expenses directly related toexploration and development activities, but do not include any costs related to production, selling or generalcorporate administrative activities.

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costsless related deferred income taxes or the cost center ceiling, with any excess above the cost center ceilingcharged to operations as a full-cost ceiling impairment. The cost center ceiling is defined as the sum of (a)the present value discounted at 10 percent of future net revenues of proved oil and natural gas reserves, plus(b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fairvalue of unproved and unevaluated properties included in the costs being amortized, if any, less (d) incometax effects related to differences between the book and tax basis of the properties involved. Future netrevenues from proved non-producing and proved undeveloped reserves are reduced by the estimated costsof developing these reserves. The fair value of our derivative instruments is not included in the ceiling testcomputation as we do not designate these instruments as hedge instruments for accounting purposes.

The estimated present value of after-tax future net cash flows from proved oil and natural gas reservesis highly dependent on the commodity prices used in these estimates. These estimates are determined inaccordance with guidelines established by the SEC for estimating and reporting oil and natural gas reserves.Under these guidelines, oil and natural gas reserves are estimated using then-current operating andeconomic conditions, with no provision for price and cost escalations in future periods except by contractualarrangements. In 2009, the SEC provided new guidelines for estimating and reporting oil and natural gasreserves. Under these new guidelines, the commodity prices used to estimate oil and natural gas reserveswere changed from last-day-of-the-year prices to an unweighted, arithmetic average offirst-day-of-the-month prices for the previous 12-month period.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production methodbased upon production and estimates of proved reserves quantities. Unproved and unevaluated propertycosts are excluded from the amortization base used to determine depletion. Unproved and unevaluatedproperties are assessed for impairment on a periodic basis based upon changes in operating or economicconditions. This assessment includes consideration of the following factors, among others: the assignment

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of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drillingactivity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediatelyincluded in the amortization base. Exploratory dry holes are included in the amortization base immediatelyupon the determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with nogain or loss recognized, unless such adjustments would significantly alter the relationship between netcapitalized costs and proved reserves of oil and natural gas. All costs related to production activities andmaintenance and repairs are expensed as incurred. Significant workovers that increase the properties’reserves are capitalized.

Other property and equipment are stated at cost. Computer equipment, furniture, software and otherequipment are depreciated over their useful life (five to seven years) using the straight-line method. Supportequipment and facilities include the pipelines and salt water disposal systems owned by LongwoodGathering and Disposal Systems, LP and are depreciated over a 30-year useful life using the straight-line,mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lifeor the term of the lease.

Asset Retirement Obligations

We recognize the fair value of an asset retirement obligation in the period in which it is incurred if areasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at itsestimated present value, with an offsetting increase recognized in oil and natural gas properties or supportequipment and facilities on the balance sheet. Periodic accretion of the discounted value of the estimatedliability is recorded as an expense in the consolidated statement of operations. In general, our future assetretirement obligations relate to future costs associated with plugging and abandonment of our oil and naturalgas wells, removal of equipment and facilities from leased acreage and returning such land to its originalcondition. The amounts recognized are based on numerous estimates and assumptions, including futureretirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in our estimate or iffederal or state regulators enact new plugging and abandonment requirements. At the time of actualplugging and abandonment of our oil and natural gas wells, we include any gain or loss associated with theoperation in the amortization base to the extent that the actual costs are different from the estimated liability.

Derivative Financial Instruments

From time to time, we use derivative financial instruments to hedge our exposure to commodity pricerisk associated with oil and natural gas prices. These instruments consist of put and call options in the formof costless collars. Our derivative financial instruments are recorded on the balance sheet as either an assetor a liability measured at fair value. We have elected not to apply hedge accounting for our existingderivative financial instruments, and as a result, we recognize the change in derivative fair value betweenreporting periods currently in our consolidated statement of operations. The fair value of our derivativefinancial instruments is determined based on our counterparty’s valuation model which we verify for itsreasonableness with an independent third party valuation using observable, market-corroborated inputs.Realized gains and realized losses from the settlement of derivative financial instruments and unrealizedgains and unrealized losses from valuation changes in the remaining unsettled derivative financialinstruments are reported under “Revenues” in our consolidated statement of operations.

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Revenue Recognition

We follow the sales method of accounting for our oil and natural gas revenue, whereby we recognizerevenue, net of royalties, on all oil or natural gas sold to purchasers regardless of whether the sales areproportionate to our ownership in the property. Under this method, revenue is recognized at the time the oiland natural gas are produced and sold, and we accrue for revenue earned but not yet received.

Stock-based Compensation

In 2003, our board of directors and shareholders approved the Matador Resources Company 2003Stock and Incentive Plan, or the 2003 Plan. The persons eligible to receive awards under the 2003 Planinclude our employees, directors, officers, consultants or advisors. The 2003 Plan is administered by ourboard of directors, which determines the number of options or restricted shares to be granted, the effectivedates and terms of the grants, the option or restricted share price and the vesting period. In the absence of anestablished market for shares of our common stock as a private company, the board of directors determinesthe fair market value of our common stock for purposes of awards under the 2003 Plan. We typically usenewly issued shares to satisfy option exercises or restricted share grants.

Our 2012 Long-Term Incentive Plan has been adopted, effective January 1, 2012. This plan permits thegranting of long-term equity and cash incentive awards to our Named Executive Officers, key employees,consultants and non-employee directors. See “Compensation of Named Executive Officers — Long-TermIncentive Plan.”

Non-qualified stock option expense is recognized in our consolidated statement of operations on thedate of the grant. Incentive stock options vest over four years, and the associated compensation expense isrecognized on a straight-line basis over the vesting period. Prior to November 22, 2010, all of ouroutstanding stock options were classified as equity instruments, with all stock-based compensation expensemeasured on the date of grant and recognized over the vesting period, if any. On November 22, 2010, wechanged our method of accounting for outstanding stock options, reclassifying all outstanding stock optionsfrom equity to liability instruments. This change was made as a result of purchasing shares from certain ofour employees to assist them in the exercise of outstanding options of our Class A common stock. As aresult, at December 31, 2010 and at September 30, 2011, we measured and recognized the fair value of theliability associated with our outstanding stock options using an estimated fair value of our Class A commonstock. On occasion, the board of directors grants restricted shares to eligible participants under the 2003Plan. The fair value of these restricted stock awards are recognized based upon the fair value of our stock asdetermined by the board of directors on the date of the grant. Depending on the terms of the restricted sharegrant, the fair value of the award may be recognized on the date of grant in our consolidated statement ofoperations, or in the case of a restricted share award that vests over time, the fair value of the award ismeasured on the date of grant and recognized on a straight-line basis over the vesting period.

Income Taxes

We file a United States federal income tax return and several state tax returns, a number of whichremain open for examination. The tax years open for examination for the federal tax return are 2007, 2008,2009 and 2010. The tax years open for examination by the state of Texas are 2008, 2009 and 2010. The taxyears open for examination by the state of New Mexico are 2008, 2009 and 2010. The tax years open forexamination by the state of Louisiana are 2007, 2008, 2009 and 2010. At January 16, 2012, our 2007, 2008

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and 2009 income and franchise tax returns were under examination by the state of Louisiana. As a result ofpreliminary findings received by us from the state of Louisiana, we recorded an income tax refund of$45,636, a franchise tax assessment of $91,995 and an associated interest expense of $12,429 for the threeand nine months ended September 30, 2011.

We account for income taxes using the asset and liability approach for financial accounting andreporting. We evaluate the probability of realizing the future benefits of our deferred tax assets and providea valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an incometax benefit in the future does not meet the more likely than not criteria for recognition.

We account for uncertainty in income taxes by recognizing the financial statement benefit of a taxposition only after determining that the relevant tax authority would more likely than not sustain theposition following an audit. For tax positions meeting the more likely than not threshold, the amountrecognized in the financial statements is the benefit that has a greater than 50 percent likelihood of beingrealized upon ultimate settlement with the relevant tax authority.

We have evaluated all tax positions for which the statute of limitations remained open, and we believethat the material positions taken would more likely than not be sustained by examination. Therefore, atDecember 31, 2010, we had not established any reserves for, nor recorded any unrecognized tax benefitsrelated to, uncertain tax positions. When necessary, we include interest assessed by taxing authorities in“Interest expense” and penalties related to income taxes in “Other expense” on our consolidated statementof operations. At December 31, 2010, 2009 and 2008, we did not record any interest or penalties related toincome tax.

Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue

Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associatedfuture net revenues. While the SEC has recently adopted rules which allow us to disclose proved, probableand possible reserves, we have elected to present only proved reserves in this prospectus. The SEC’s revisedrules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience andengineering data, can be estimated with reasonable certainty to be economically producible — from a givendate forward, from known reservoirs, and under existing economic conditions, operating methods andgovernment regulations — prior to the time at which contracts providing the right to operate expire, unlessevidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilisticmethods are used for the estimation. The project to extract the hydrocarbons must have commenced or theoperator must be reasonably certain that it will commence the project within a reasonable time. Ourengineers and technical staff must make many subjective assumptions based on their professional judgmentin developing reserves estimates. Reserves estimates are updated at least annually and consider recentproduction levels and other technical information about each well. Estimating oil and natural gas reserves iscomplex and is not exact because of the numerous uncertainties inherent in the process. The process relieson interpretations of available geological, geophysical, petrophysical, engineering and production data. Theextent, quality and reliability of both the data and the associated interpretations can vary. The process alsorequires certain economic assumptions, including, but not limited to, oil and natural gas prices, revenues,development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oiland natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities ofrecoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates aregenerally different from the quantities of oil and natural gas that are ultimately recovered. Any significant

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variance could materially and adversely affect our future reserves estimates, financial position, results ofoperations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If suchrevisions are significant, they could significantly affect future amortization of capitalized costs and result inimpairment of assets that may be material.

Recent Accounting Pronouncements

Subsequent Events. We incorporate the accounting and disclosure requirements for subsequent eventsin our financial statements. In accordance with GAAP, new terminology was introduced recently whichdefines the date through which management must evaluate subsequent events and lists the circumstancesunder which an entity must recognize and disclose events or transactions occurring after the balance sheetdate. We adopted this guidance at December 31, 2009.

Oil and Natural Gas Reserves Reporting Requirements. In January 2009, the SEC issued TheModernization of Oil and Gas Reporting, Final Rule. In January 2010, the Financial Accounting StandardsBoard, or FASB, amended Topic 932, Extractive Activities — Oil and Gas to align with this rule. Thechanges are designed to modernize and update the oil and natural gas disclosure requirements to align themwith current practices and changes in technology. The new rules made a number of important changesincluding the following: (i) expanded the definition of oil and natural gas producing activities to include theextraction of saleable hydrocarbons from oil sands, shale, coalbeds or other nonrenewable natural resources,(ii) amended the required price for estimating economic quantities for year-end reserves reporting to be theunweighted, arithmetic average of the first-day-of-the-month price for each month within the previous12-month period, rather than the year-end price and (iii) permitted proved reserves to be claimed beyondthose development spacing areas that are immediately adjacent to developed spacing areas if it can beestablished with reasonable certainty that these reserves are economically producible. At December 31,2009, we adopted the provisions of this new rule, and we have applied this new guidance for the reservesestimates shown for December 31, 2010 and 2009 and September 30, 2011 included herein.

Derivative Financial Instruments. At December 31, 2008, we adopted new guidance to providequalitative disclosures about our objectives and strategies for using derivative financial instruments and toprovide a tabular presentation of quantitative information for derivatives designated as hedges, hedged itemsand other derivatives. This new guidance was effective for annual financial periods beginning afterNovember 15, 2008. As its only requirement is to enhance disclosures, the new guidance had no materialimpact on our consolidated financial statements.

Fair Value. In May 2011, the FASB issued Accounting Standards Update, or ASU, 2011-04,Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP andIFRS, or ASU 2011-04. ASU 2011-04 amends Accounting Standards Codification, or ASC, 820, Fair ValueMeasurements, or ASC 820, providing a consistent definition and measurement of fair value, as well assimilar disclosure requirements between GAAP and International Financial Reporting Standards. ASU2011-04 changes certain fair value measurement principles, clarifies the application of existing fair valuemeasurements and expands the ASC 820 disclosure requirements, particularly for Level 3 fair valuemeasurements. The adoption of ASU 2011-04 is not expected to have a material impact on our consolidatedfinancial statements, but may require certain additional disclosures. The amendments in ASU 2011-04 are tobe applied prospectively. For public entities, the amendments are effective during interim and annualperiods beginning after December 15, 2011.

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In January 2010, the FASB issued authoritative guidance to update certain disclosure requirements andadded two new disclosure requirements related to fair value measurements. The guidance requires a grosspresentation of activities within the Level 3 roll forward and adds a new requirement to disclose details ofsignificant transfers in and out of Level 1 and 2 measurements and the reasons for the transfers. The newdisclosures are required for all companies that are required to provide disclosures about recurring andnon-recurring fair value measurements, and are effective the first interim or annual reporting periodbeginning after December 15, 2009, except for the gross presentation of the Level 3 roll forwardinformation, which is required for annual reporting periods beginning after December 15, 2010 and forinterim reporting periods within those years. We adopted the first portion of this guidance beginningJanuary 1, 2010. We do not expect the adoption of this new guidance to have a significant impact on ourfinancial position, results of operations or cash flows.

In September 2006, the FASB issued authoritative guidance for using fair value to measure assets andliabilities. This guidance applies whenever other standards require or permit assets or liabilities to bemeasured at fair value, but it does not expand the use of fair value in any new circumstances. In February2009, the FASB delayed the effective date by one year for non-financial assets and liabilities. We adoptedthis guidance effective January 1, 2008, but delayed guidance relating to non-financial assets and liabilitiesuntil January 1, 2009. The adoption of this guidance did not have a significant impact on our financialposition, results of operations or cash flows.

In February 2007, the FASB issued authoritative guidance permitting entities to choose to measurecertain financial instruments and other items at fair value. The objective is to improve financial reporting byproviding entities with the opportunity to mitigate volatility in reported earnings caused by measuringrelated assets and liabilities differently without having to apply complex hedge accounting provisions.Unrealized gains and losses on any items for which the fair value measurement option is elected are to bereported in the consolidated statement of operations. We adopted this guidance at January 1, 2008. Weelected not to measure any eligible items using the fair value option in accordance with this guidance, andtherefore, it did not have an impact on our financial position, results of operations or cash flows.

Uncertainty in Income Taxes. At January 1, 2008, we adopted the accounting guidance related toaccounting for uncertainty in income taxes which provides for the financial statement benefit of a taxposition as being recognized only after determining that the relevant tax authority would more likely thannot sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, theamount recognized in the financial statements is the benefit that has a greater than 50 percent likelihood ofbeing realized upon ultimate settlement with the relevant tax authority. Following adoption, we evaluated alltax positions for which the statute of limitations remained open, and management believes that the materialpositions taken would more likely than not be sustained by examination. We do not expect any change inunrecognized tax benefits in the next 12 months.

Internal Controls and Procedures

Prior to the completion of this offering, we have been a private company and have maintained internalcontrols and procedures in accordance with being a private company. We have maintained limitedaccounting personnel to perform our accounting processes and limited other supervisory resources withwhich to address our internal control over financial reporting. In connection with our audit for the yearended December 31, 2010, our independent registered public accountants identified and communicatedmaterial weaknesses related to accounting for deferred income taxes, impairment of oil and natural gas

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properties, assessment of unproved and unevaluated properties and the administration of our stock plan.A material weakness is a control deficiency, or a combination of control deficiencies, in internal controlover financial reporting, such that there is reasonable possibility that a material misstatement of our annualor interim financial statements will not be prevented or detected on a timely basis.

We have begun the process of evaluating our internal control over financial reporting and will continueto work with our auditors to put into place new accounting process and control procedures to address theissues set forth above. However, we will not complete this process until well after this offering iscompleted. We cannot predict the outcome of this process at this time.

We are not currently required to comply with the SEC’s rules implementing Section 404 of theSarbanes-Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of ourinternal control over financial reporting for that purpose. Upon becoming a public company, we will berequired to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act, which willrequire our management to certify financial and other information in our quarterly and annual reports and toprovide an annual management report on the effectiveness of our internal control over financial reporting.We will not be required to make our first assessment of our internal control over financial reporting until theyear following the year that our first annual report is filed or required to be filed with the SEC. To complywith the requirements of being a public company, we will need to upgrade our systems, includinginformation technology, implement additional financial and management controls, reporting systems andprocedures and hire additional accounting and financial reporting staff.

Further, our independent registered public accountants are not yet required to formally attest to theeffectiveness of our internal control over financial reporting until the year following the year that our firstannual report is required to be filed with the SEC. Once it is required to do so, our independent registeredpublic accounting firm may issue a report that is adverse in the event it is not satisfied with the level atwhich our controls are documented, designed, operated or reviewed. Our remediation efforts may not enableus to remedy or avoid material weaknesses in the future.

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to a variety of market risks including commodity price risk, interest rate risk andcounterparty and customer risk. We address these risks through a program of risk management including theuse of derivative financial instruments.

Commodity price exposure. We are exposed to market risk as the prices of oil and natural gas fluctuateas a result of changes in supply and demand and other factors. To partially reduce price risk caused by thesemarket fluctuations, we have entered into derivative financial instruments in the past and expect to enterinto derivative financial instruments in the future to cover a significant portion of our future production.

We use costless (or zero-cost) collars to manage risks related to changes in oil and natural gas prices.A costless collar provides us with downside price protection through the purchase of a put option which isfinanced through the sale of a call option. Because the call option proceeds are used to offset the cost of theput option, this arrangement is initially “costless” to us. At December 31, 2010, 2009 and 2008 and atSeptember 30, 2011, we used costless collar options to reduce the volatility of natural gas prices on asignificant portion of our future expected natural gas production.

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We record all derivative financial instruments at fair value. The fair value of our derivative financialinstruments is determined based on our counterparty’s valuation model which we verified for itsreasonableness annually with an independent third party valuation using observable, market-corroboratedinputs. Comerica Bank is the single counterparty for all of our derivative instruments. We have made noadjustments to the fair value amounts recognized on the balance sheet for these derivative instruments toaccount for the credit standing of Comerica Bank.

The following is a summary of our open natural gas costless collar contracts at November 30, 2011:

Commodity Calculation Period Notional Quantity Price FloorPrice

CeilingFair Value

of Asset

(MMBtu/month) ($/MMBtu) ($/MMBtu) (thousands)Natural Gas 01/01/2010 — 12/31/2011 50,000 5.25 8.10 $ 94Natural Gas 01/01/2010 — 12/31/2011 50,000 5.50 7.65 107Natural Gas 01/01/2010 — 12/31/2011 50,000 5.00 8.65 82Natural Gas 01/01/2010 — 12/31/2011 50,000 5.50 7.70 107Natural Gas 01/01/2011 — 12/31/2011 90,000 5.50 7.85 192Natural Gas 07/01/2011 — 12/31/2012 300,000 4.50 5.60 3,392Natural Gas 07/01/2011 — 07/31/2013 150,000 4.50 5.75 2,210Natural Gas 01/01/2012 — 12/31/2012 150,000 4.25 6.17 1,200

Total $7,384

All of our existing natural gas derivative contracts will expire at varying times during 2011, 2012 and2013. In November and December 2011, we entered into various costless collar transactions to mitigate ourexposure to oil price volatility for the first time. The following table is a summary of our open oil costlesscollar contracts at November 30, 2011.

Commodity Calculation Period Notional Quantity Price FloorPrice

CeilingFair Value

of Asset

(Bbl/month) ($/Bbl) ($/Bbl) (thousands)Oil 12/01/2011 — 12/31/2012 20,000 90.00 104.20 $(346)Oil 01/01/2013 — 12/31/2013 20,000 85.00 102.25 (220)

Total $(566)

For each calculation period, the specified price for determining the realized gain or loss to us pursuantto any of these oil hedging transactions is the arithmetic average of the settlement prices for the NYMEXWest Texas Intermediate oil futures contract for the first nearby month corresponding to the calculationperiod’s calendar month. When the settlement price is below the price floor established by these collars, wereceive from Comerica Bank, as counterparty, an amount equal to the difference between the settlementprice and the price floor multiplied by the contract oil volume hedged. When the settlement price is abovethe price ceiling established by these collars, we pay Comerica Bank, as counterparty, an amount equal tothe difference between the settlement price and the price ceiling multiplied by the contract oil volumehedged.

Effect of Recent Derivatives Legislation. On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which is intended tomodernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things,sets forth the new framework for regulating certain derivative products including the commodity hedges ofthe type used by us, but many aspects of this law are subject to further rulemaking and will take effect over

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several years. As a result, it is difficult to anticipate the overall impact of the Dodd-Frank Act on our abilityor willingness to continue entering into and maintaining such commodity hedges and the terms thereof.Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is thepossibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter intoand maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementationof position limits and additional regulatory requirements on our derivative arrangements, which couldinclude new margin, reporting and clearing requirements. In addition, this legislation could have asubstantial impact on our counterparties and may increase the cost of our derivative arrangements in thefuture. See “Risk Factors — The derivatives legislation adopted by Congress could have an adverse impacton our ability to hedge risks associated with our business.”

Interest rate risk. We do not use interest rate derivatives to alter interest rate exposure in an attempt toreduce interest rate expense on existing debt since we borrowed under our existing credit agreement for thefirst time in December 2010 and had $60.0 million in revolving debt outstanding at September 30, 2011 atan interest rate of 1.875% plus a Eurodollar-based rate, which equated to approximately 2.2% per annum atSeptember 30, 2011. In addition to our revolving borrowings, in May 2011, we borrowed $25.0 million in aterm loan pursuant to the credit agreement. The term loan bore interest at an annual rate of 5% plus aEurodollar-based rate, which equated to approximately 5.3% at September 30, 2011. The term loan wasrefinanced through revolving borrowings in December 2011 under our amended and restated creditagreement. At January 27, 2012, all borrowings under our credit agreement bore interest at a variable rate of3.25% plus a Eurodollar-based rate per annum, which equated to approximately 3.5% per annum. If weincur any indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interestrate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverageof the debt portfolio.

Counterparty and customer credit risk. Joint interest receivables arise from billing entities which ownpartial interest in the wells we operate. These entities participate in our wells primarily based on theirownership in leases on which we wish to drill. We have limited ability to control participation in our wells.We are also subject to credit risk due to concentration of our oil and natural gas receivables with severalsignificant customers. The inability or failure of our significant customers to meet their obligations to us ortheir insolvency or liquidation may adversely affect our financial position, results of operations and cashflows. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event ofnonperformance by counterparties.

While we do not require our customers to post collateral and we do not have a formal process in placeto evaluate and assess the credit standing of our significant customers for oil and natural gas receivables andthe counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties aswe deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’scredit rating, latest financial information and, in the case of a customer with which we have receivables, itshistorical payment record, the financial ability of the customer’s parent company to make payment if thecustomer cannot and undertaking the due diligence necessary to determine credit terms and credit limits.The counterparty on our derivative instruments currently in place is Comerica Bank and we are likely toenter into any future derivative instruments with Comerica Bank.

Impact of Inflation. Inflation in the United States has been relatively low in recent years and did nothave a material impact on our results of operations for the years ended December 31, 2010, 2009 and 2008.Although the impact of inflation has been generally insignificant in recent years, it is still a factor in the

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United States economy and we tend to specifically experience inflationary pressure on the cost of oilfieldservices and equipment with increases in oil and natural gas prices and with increases in drilling activity inour areas of operations, including the Eagle Ford shale and Haynesville shale plays. See “— Overview.”See also “Risk Factors — The unavailability or high cost of drilling rigs, completion equipment andservices, supplies and personnel, including hydraulic fracturing equipment and personnel, could adverselyaffect our ability to establish and execute exploration and development plans within budget and on a timelybasis, which could have a material adverse effect on our financial condition, results of operations and cashflows.”

Off-Balance Sheet Arrangements

At December 31, 2010 and September 30, 2011, we did not have any off-balance sheet arrangements.

Changes in Accountants

Grant Thornton LLP, or Grant Thornton, performed audits of our consolidated financial statements forthe fiscal years ended December 31, 2008 and 2009. Grant Thornton’s reports did not contain an adverseopinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope oraccounting principles.

On or about June 1, 2010, following the completion of Grant Thornton’s audit of our financialstatements for the year ended December 31, 2009, our Audit Committee determined not to renew GrantThornton’s engagement as our independent accountant. On October 28, 2010, our board of directorsunanimously approved the appointment of Ernst & Young, LLP, or Ernst & Young, as our independentaccountant commencing with work to be performed in relation to our nine month period endedSeptember 30, 2010. We had no occasion in 2008 and 2009 and any subsequent interim period prior toOctober 28, 2010 upon which we consulted with Ernst & Young on any matters.

During the fiscal years ended December 31, 2008 and 2009, and the subsequent interim period throughJune 1, 2010, there were (i) no disagreements with Grant Thornton on any matter of accounting principlesor practices, financial statement disclosure or auditing scope or procedure, which disagreement(s), if notresolved to Grant Thornton’s satisfaction, would have caused Grant Thornton to make reference to thesubject matter of the disagreement(s) in connection with its reports for such years, and (ii) no reportableevents within the meaning set forth in Item 304(a)(1)(v) of Regulation S-K.

Prior to the completion of Ernst & Young’s audit of our financial statements for the nine month periodended September 30, 2010, on or about February 28, 2011, we mutually agreed with Ernst & Young toterminate our relationship. The decision to discontinue the audit services of Ernst & Young was mutual andwas approved by our Board of Directors and Audit Committee effective at February 28, 2011. FromOctober 28, 2010 through February 28, 2011, there were (i) no disagreements with Ernst & Young on anymatter of accounting principles or practices, financial statement disclosure or auditing scope or procedure,which disagreement(s), if not resolved to Ernst & Young’s satisfaction, would have caused Ernst & Youngto make reference to the subject matter of the disagreement(s) in connection with its report for the nine-month period ended September 30, 2010, and (ii) no reportable events within the meaning set forth inItem 304(a)(1)(v) of Regulation S-K.

Effective at February 28, 2011, our Audit Committee unanimously approved the reappointment ofGrant Thornton as our independent accountant to audit our financial statements for the year ended

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December 31, 2010. Prior to our reengagement of Grant Thornton, we had discussions with Grant Thorntonregarding whether they had the capacity, availability and desire to reengage as our auditor going forward.Prior to these reengagement discussions, during the period from approximately the middle of December2010 through the end of January 2011, there were also discussions regarding the accounting for ouroutstanding stock options, specifically regarding the liability versus equity classification of the outstandingstock options, and our accounting for income taxes related to the calculation of deferred taxes related to ourstatutory depletion calculation in 2008 and 2009. Based on discussions held prior to our reengagement ofGrant Thornton, it was concluded that the accounting treatment continued to be appropriate with noadjustments to the previously issued financial statements necessary. The aforesaid discussions did notaddress any accounting issues related to the fiscal year 2010. We had no occasion between June 1, 2010 andFebruary 28, 2011 upon which we consulted with Grant Thornton on any other matters.

Both Grant Thornton and Ernst & Young have been provided with a copy of this disclosure and havefurnished to us a letter addressed to the Securities and Exchange Commission stating that they agree withthe statements about such firms contained herein.

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BUSINESS

Overview

We are an independent energy company engaged in the exploration, development, production andacquisition of oil and natural gas resources in the United States, with a particular emphasis on oil andnatural gas shale plays and other unconventional resource plays. Our current operations are locatedprimarily in the Eagle Ford shale play in south Texas and the Haynesville shale play in northwest Louisianaand east Texas. These plays are a key part of our growth strategy, and we believe they currently representtwo of the most active and economically viable unconventional resource plays in North America. We expectthe majority of our near-term capital expenditures will focus on increasing our production and reserves fromthe Eagle Ford and Haynesville shale plays as we seek to capitalize on the relative economics of each play.In addition to these primary operating areas, we have acreage positions in southeast New Mexico and westTexas and in southwest Wyoming and adjacent areas in Utah and Idaho where we continue to identify newoil and natural gas prospects.

We were founded in July 2003 by Joseph Wm. Foran, Chairman, President and CEO, and Scott E.King, Co-Founder and Vice President, Geophysics and New Ventures, with an initial equity investment ofapproximately $6.0 million. Shortly thereafter, investors contributed approximately $46.8 million to providea total initial capitalization of approximately $52.8 million at a purchase price of $3.33 per share. Most ofthis initial capital was provided by the same institutional and individual investors who helped capitalizeMr. Foran’s previous company, Matador Petroleum Corporation.

Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran OilCompany with $270,000 in contributed capital from 17 friends and family members. Foran Oil Companywas later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988.Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it wassold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately$388.5 million. Matador Petroleum Corporation grew primarily through a strategy focused on acquisitionand exploitation, including in the Permian and Delaware basins in west Texas and southeast New Mexico.

With an average of more than 25 years of oil and natural gas industry experience, our managementteam has extensive expertise in exploring for and developing hydrocarbons in multiple U.S. basins.Members of our management team have participated in the assimilation of numerous lease positions and inthe drilling and completion of hundreds of vertical and horizontal wells in unconventional resource plays.

Since our first well in 2004, we have drilled or participated in drilling 213 wells through September 30,2011, including 83 Haynesville and six Eagle Ford wells. From December 31, 2008 through September 30,2011, we grew our estimated proved reserves from 20.0 Bcfe to 161.8 Bcfe. At September 30, 2011, 35% ofour estimated proved reserves were proved developed reserves and 96% of our estimated proved reserveswere natural gas. We also grew our average daily production by approximately 162% from 9.0 MMcfe perday for the year ended December 31, 2008 to 23.6 MMcfe per day for the year ended December 31, 2010.In addition, as a result of production from new wells that were completed in 2011, our daily production forthe nine months ended September 30, 2011 averaged approximately 42.5 MMcfe per day. We haveachieved this growth while lowering operating costs (consisting of lease operating expenses and productiontaxes and marketing expenses) from $1.91 per Mcfe for the year ended December 31, 2008, to$0.90 per Mcfe for the nine months ended September 30, 2011, or a decrease of approximately 53%.

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The following table presents certain summary data for each of our operating areas as of and for thenine months ended September 30, 2011:

ProducingWells

Total IdentifiedDrilling Locations(1)

Estimated Net ProvedReserves Avg. Daily

Production(MMcfe)Net Acreage Gross Net Gross Net Bcfe(2)

%Developed

South Texas:Eagle Ford . . . . . . . . . . . . . . . . . . . . . 28,906 5.0 3.4 197.0 157.1 8.4 51.0 3.2Austin Chalk . . . . . . . . . . . . . . . . . . . 14,849 – – 16.0 16.0 – – –

Area Total(3) . . . . . . . . . . . . . . . . . . 28,906 5.0 3.4 213.0 173.1 8.4 51.0 3.2

NW Louisiana/E Texas:Haynesville . . . . . . . . . . . . . . . . . . . . 14,705 83.0 10.6 545.0 103.9 136.6 25.4 32.1Cotton Valley(4) . . . . . . . . . . . . . . . . . 23,236 108.0 71.7 60.0 36.0 16.1 100.0 7.0

Area Total(5) . . . . . . . . . . . . . . . . . . 25,477 191.0 82.3 605.0 139.9 152.7 33.3 39.1

SW Wyoming, NEUtah, SE Idaho . . . . . . . . . . . . . . . . . . . 135,862 – – – – – – –

SE New Mexico, West Texas . . . . . . . . . . 7,519 13.0 5.7 – – 0.7 100.0 0.2

Total . . . . . . . . . . . . . . . . . . . . . . . 197,764 209.0 91.4 818.0 313.0 161.8 34.5 42.5

(1) These locations have been identified for potential future drilling and are not currently producing. In addition, the total net identifieddrilling locations is calculated by multiplying the gross identified drilling locations in an operating area by our working interestparticipation in such locations. At September 30, 2011, these identified drilling locations included 2 gross and 2 net locations to whichwe have assigned proved undeveloped reserves in the Eagle Ford and 95 gross and 15 net locations to which we have assigned provedundeveloped reserves in the Haynesville. We have no proved undeveloped reserves assigned to identified drilling locations in the AustinChalk or Cotton Valley at September 30, 2011.

(2) These estimates were prepared by our engineering staff and audited by independent reservoir engineers, Netherland, Sewell &Associates, Inc.

(3) Some of the same leases cover the net acres shown for the Eagle Ford formation and the Austin Chalk formation, a shallower formationthan the Eagle Ford formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for southTexas. This total includes acreage that we are producing from or that we believe to be prospective for these formations.


(5) Some of the same leases cover the net acres shown for the Haynesville formation and the Cotton Valley formation, a shallower formationthan the Haynesville formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage fornorthwest Louisiana/east Texas. This total includes acreage that we are producing from or that we believe to be prospective for theseformations.

At September 30, 2011, our properties included approximately 52,000 gross acres and 29,000 net acresin the Eagle Ford shale play in Atascosa, DeWitt, Dimmit, Karnes, La Salle, Gonzales, Webb, Wilson andZavala Counties in south Texas. We believe that approximately 85% of our Eagle Ford acreage isprospective predominantly for oil or liquids production. In addition, portions of the acreage are alsoprospective for other targets, such as the Austin Chalk, Olmos and Buda, from which we expect to producepredominantly oil and liquids. Approximately 80% of our Eagle Ford acreage is either held by production ornot burdened by lease expirations before 2013. We have begun to explore and develop our Eagle Fordposition and from November 2010 through December 2011, we completed our first seven operated wells inthis area (see “ — Recent Developments”). We have identified 197 gross locations and 157 net locations forpotential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties,estimated recoveries from nearby wells based on available public data, drilling densities observed fromother operators, estimated drilling and completion costs, spacing and other rules established by regulatory

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authorities and surface considerations, among others. At September 30, 2011, we have identified potentialdrilling locations on approximately 75% of our net Eagle Ford acreage. As we explore and develop ourEagle Ford acreage further, we believe it is possible that we may identify additional locations for drilling.At September 30, 2011, these identified potential future drilling locations in the Eagle Ford shale playincluded 2 gross and 2 net locations to which we have assigned proved undeveloped reserves.

In addition, at September 30, 2011, we had approximately 23,000 gross acres and 15,000 net acres inthe Haynesville shale play in northwest Louisiana and east Texas. Based on our analysis of geologic andpetrophysical information (including total organic carbon content and maturity, resistivity, porosity andpermeability, among other information), well performance data and information available to us related todrilling activity and results from wells drilled across the Haynesville shale play, almost 5,500 of our netacres are located in what we believe is the core area of the play. We believe the core area of the playincludes that area in which the most Haynesville wells have been drilled by operators and from which weanticipate natural gas recoveries would likely exceed 6 Bcf per well. Just over 90% of our Haynesvilleacreage is held by production from the Haynesville or other formations, and we believe much of it is alsoprospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, webelieve approximately 1,700 of these net acres are prospective for the Middle Bossier shale play.

At September 30, 2011, we have identified 545 gross locations and 104 net locations for potentialfuture drilling in our Haynesville acreage. These locations have been identified on a property-by-propertybasis and take into account criteria such as anticipated geologic conditions and reservoir properties,estimated recoveries from our producing Haynesville wells and other nearby wells based on available publicdata, drilling densities observed from other operators including on some of our non-operated properties,estimated drilling and completion costs, spacing and other rules established by regulatory authorities andsurface conditions, among others. Of the 545 gross locations identified for future drilling, 470 of theselocations (53 net locations) have been identified within the 5,500 net acres that we believe are located in thecore area of the Haynesville play. As we explore and develop our Haynesville acreage further, we believe itis possible that we may identify additional locations for future drilling. At September 30, 2011, theseidentified potential future drilling locations included 95 gross and 15 net locations in the Haynesville shaleplay to which we have assigned proved undeveloped reserves.

We also have a large unevaluated acreage position in southwest Wyoming and adjacent areas in Utahand Idaho where we began drilling our initial well in February 2011 to test the Meade Peak natural gasshale. We reached a depth of 8,200 feet, approximately 300 feet above the top of the Meade Peak shale,before having operations suspended for several months due to wildlife restrictions. We resumed operationson this initial test well in September 2011 and completed drilling and coring operations on this well inNovember 2011. In addition, we have leasehold interests in the Delaware and Midland Basins in southeastNew Mexico and west Texas where we are developing new oil and natural gas prospects.

We are active both as an operator and as a co-working interest owner with larger industry participantsincluding affiliates of Chesapeake Energy Corporation, EOG Resources, Inc., Royal Dutch Shell plc andothers. Of the 213 gross wells we have drilled or participated in drilling, we drilled approximately half ofthese wells as the operator. At September 30, 2011, we were the operator for approximately 80% of ourEagle Ford and 70% of our Haynesville acreage, including approximately 22% of our acreage in what webelieve is the core area of the Haynesville play. A large portion of our acreage in that core area is operatedby a subsidiary of Chesapeake Energy Corporation. We also operate all of our acreage in southwestWyoming and the adjacent areas of Utah and Idaho, as well as the vast majority of our acreage in southeastNew Mexico and west Texas.

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We are a non-operating working interest participant with affiliates of Chesapeake Energy Corporation,Royal Dutch Shell plc and several other companies in the Haynesville shale and with EOG Resources, Inc.in the Eagle Ford shale. We have entered into a joint operating agreement with an affiliate of ChesapeakeEnergy Corporation governing the Haynesville operations underlying our Elm Grove/Caspiana properties insouthern Caddo Parish, Louisiana (see “–Other Significant Prior Events – Chesapeake Transaction”) and ajoint operating agreement with EOG Resources, Inc. governing all operations on our joint acreage inAtascosa County, Texas. We have not entered into a joint operating agreement with Royal Dutch Shell plcor certain other operators of wells in the Haynesville area in which we have a minority working interest.Particularly when our working interest is small, we do not always enter into formal operating agreementswith the operators, and in such cases, we rely on applicable legal and statutory authority to govern ourarrangement in accordance with industry standard practices.

Where we do have joint operating agreements with affiliates of Chesapeake Energy Corporation andEOG Resources, Inc., these agreements call for significant penalties should we elect not to participate in thedrilling and completion of a well proposed by the operator, or a non-consent well. These non-consentpenalties typically allow the operator to recover up to 400% of its costs to drill, complete and equip the non-consent well from the well’s future net revenue prior to us being allowed to participate in the non-consentwell for our original working interest. Ultimately, the amount of these penalties may result in us having noparticipation at all in the non-consent well. We also have the right to propose wells under these jointoperating agreements, and the same non-consent penalties apply to the operator should it elect not toconsent to a well that we propose.

While we do not have direct access to our operating partners’ drilling plans with respect to future welllocations, we do attempt to maintain ongoing communications with the technical staff of these operators inan effort to understand their drilling plans for purposes of our capital expenditure budget and our booking ofany related proved undeveloped well locations. We review these locations with Netherland, Sewell &Associates, Inc., our independent reservoir engineers, on a periodic basis to ensure their concurrence withour estimates of these drilling plans and our approach to booking these reserves.

Our net proceeds from this offering, after repaying the then outstanding borrowings under ourrevolving credit agreement ($123.0 million at January 27, 2012, excluding outstanding letters of credit)when taken together with our cash flows and future potential borrowings under our credit agreement, will beused to fund our 2012 capital expenditure requirements and for potential acquisitions of interests andacreage (none of which have been identified). As a result of our anticipated increases in production andreserves, we expect to have a sufficient increase in our cash flows from operations during the year endingDecember 31, 2012, as compared to our cash flows from operations in prior periods, as well as a sufficientincrease in the borrowing base under our credit agreement to help fund our 2012 capital expenditure budget.A majority of our anticipated increase in cash flows during the year ending December 31, 2012 is expectedto come from our exploration activities on unproved properties at September 30, 2011 in the Eagle Fordshale play assuming such exploration activities are successful. These anticipated increases in our cash flowsfrom operations are based upon current oil and natural gas prices and the hedges we currently have in place.If our exploration activities result in less cash flows than anticipated, we may seek additional sources ofcapital, including through borrowings under our credit agreement (assuming availability under ourborrowing base) or from the issuance of additional equity or debt securities. In addition, we may modify ourplanned capital expenditure budget for 2012 accordingly. Exploration activities are subject to a number ofrisks and uncertainties that could impact our ability to sufficiently increase our reserves, cash flows fromoperations and borrowing base under our credit agreement. See “Risk Factors — Our Exploration,Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our

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Cash Flows From Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capitalon Satisfactory Terms, Which Could Adversely Affect Our Future Growth” and “— Drilling for andProducing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with ManyUncertainties That Could Adversely Affect Our Business.” We anticipate that we may need to access futureborrowings under our credit agreement within 30 days following completion of this offering to fund aportion of our 2012 capital expenditure requirements in excess of amounts available from our cash flowsand the net proceeds of this offering. See “Use of Proceeds.”

The following table presents our 2012 anticipated capital expenditure budget of approximately$313.0 million segregated by target formation and by whether the wells are considered to be exploration ordevelopment wells.

2012 Anticipated Drilling2012 Anticipated Capital

Expenditure Budget

Gross Wells(1) Net Wells(1) (in millions)(2)

Exploration Development Total Exploration Development Total Exploration Development Total

South TexasEagle Ford . . . . . . . . . . . . . . . . 13.0 15.0 28.0 11.8 13.8 25.6 $122.3 $134.9 $257.2Austin Chalk . . . . . . . . . . . . . . 2.0 — 2.0 2.0 — 2.0 11.3 — 11.3

Area Total . . . . . . . . . . . . . . 15.0 15.0 30.0 13.8 13.8 27.6 133.6 134.9 268.5NW Louisiana / E Texas

Haynesville . . . . . . . . . . . . . . . . 6.0 19.0 25.0 0.2 1.3 1.5 1.9 11.6 13.5Cotton Valley . . . . . . . . . . . . . . — — — — — — — — —

Area Total . . . . . . . . . . . . . . 6.0 19.0 25.0 0.2 1.3 1.5 1.9 11.6 13.5SW Wyoming, NE Utah, SE

Idaho . . . . . . . . . . . . . . . . . . . . 1.0 — 1.0 0.4 — 0.4 2.5 — 2.5(3)

SE New Mexico, West Texas . . . — — — — — — — — —Other . . . . . . . . . . . . . . . . . . . . . . N/A N/A N/A N/A N/A N/A 25.0 3.5 28.5(4)

Total . . . . . . . . . . . . . . . . . . . . . . . 22.0 34.0 56.0 14.4 15.1 29.5 $163.0 $150.0 $313.0

(1) Includes wells we currently expect to drill and complete as operator, plus those wells in which we currently plan to participate as a non-operator in 2012.

(2) Our capital expenditure budget is based on our net working interests in the properties.

(3) We have a carried interest for $5.0 million of the cost of this well presuming the election of our joint venture partner to participate in thedrilling of this well.

(4) Includes $20.0 million to acquire additional leasehold interests primarily prospective for oil and liquids production in southeast NewMexico and west Texas. Also includes $6.5 million in leasehold, seismic and infrastructure expenditures attributable for the Eagle Ford.

Although we intend to allocate a portion of our 2012 capital expenditure budget to financingexploration, development and acquisition of additional interests in the Haynesville shale play, we currentlyintend to allocate approximately 84% of our 2012 capital expenditure budget to the exploration,development and acquisition of additional interests in the Eagle Ford shale play. Including these anticipatedcapital expenditures in the Eagle Ford shale play, we plan to dedicate about 94% of our 2012 anticipatedcapital expenditure budget to opportunities prospective for oil and liquids production. While we havebudgeted $313.0 million for 2012, the aggregate amount of capital we will expend may fluctuate materiallybased on market conditions and our drilling results. Since at September 30, 2011, just over 90% of ourHaynesville acreage was held by production and approximately 80% of our Eagle Ford acreage was eitherheld by production or not burdened by lease expirations before 2013, we believe we have the financialflexibility to allocate our capital when we believe it is economical and justified.

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Business Strategies

Our goal is to increase shareholder value by building reserves, production and cash flows at anattractive return on invested capital. We plan to achieve our goal by executing the following strategies:

• Focus Exploration and Development Activity on Our Eagle Ford and Haynesville Shale Assets.

We have established core acreage positions in the Eagle Ford and Haynesville shale plays,which we believe are two of the most active and economically viable shale plays in NorthAmerica. Although we intend to allocate a portion of our 2012 capital expenditure budget tofinancing exploration, development and acquisition of additional interests in the Haynesvilleshale play, we currently intend to allocate approximately 84% of our 2012 capital expenditurebudget to the exploration, development and acquisition of additional interests in the Eagle Fordshale play. Since just over 90% of our Haynesville acreage was held by production andapproximately 80% of our Eagle Ford acreage was either held by production or not burdened bylease expirations before 2013 at September 30, 2011, we have the flexibility to develop ouracreage in a disciplined manner in order to maximize the resource recovery from these assets.We believe the economics for development in these two areas are attractive at currentcommodity prices.

• Identify, Evaluate and Exploit Oil Plays to Create a More Balanced Portfolio.

Although most of our current proved reserves are classified as natural gas, we have beenevaluating various oil plays to find and execute upon opportunities that would fit well with ourexploration and operating strategies. We believe our interests in the Eagle Ford shale play willenable us to create a more balanced commodity portfolio through the drilling of locations that areprospective for oil and liquids. We believe oil and liquids opportunities represent about 94% ofour anticipated 2012 capital expenditure budget. We expect to continue to create and acquireadditional prospects and opportunities for the exploration and production of oil and liquids.

• Pursue Opportunistic Acquisitions.

We believe our management team’s familiarity with our key operating areas and their contactswith the operators and mineral owners in those regions enable us to identify high-returnopportunities at attractive prices. We actively pursue opportunities to acquire unproved andunevaluated acreage, drilling prospects and low-cost producing properties within our core areas ofoperations where we have operational control and can enhance value and performance. We viewthese acquisitions as an important component of our business strategy and intend to selectivelymake acquisitions on attractive terms that complement our growth and help us achieve economiesof scale.

• Maintain Our Financial Discipline.

As an operator, we leverage advanced technologies and integrate the knowledge, judgment andexperience of our management and technical teams. We believe our team demonstrates financialdiscipline that is achieved by our approach to evaluating and analyzing prospects and priordrilling and completion results before allocating capital and is reflected in the improvements ourteam has attained on reducing unit costs. When we are not the operator, we proactively engagewith the operators in an effort to ensure similar financial discipline. Additionally, we conduct ourown internal geological and engineering studies on these prospects and provide input on thedrilling, completion and operation of many of these non-operated wells pursuant to our

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agreements and relationships with the operators. Through these methods and practices, we believewe are well-positioned to control the expenses and timing of development and exploitation of ourproperties.

• Maintain Proactive and Ongoing Relationships with Other Industry Participants.

We believe maintaining proactive and ongoing relationships with other industry operators andvendors enhances our understanding of the shale plays and allows us to leverage their expertisewithout having to commit substantial capital. We currently participate in various drilling activitieswith larger industry participants, including affiliates of Chesapeake Energy Corporation, EOGResources, Inc., Royal Dutch Shell plc and others. We are also active participants in threeindustry shale consortia: the North American Gas Shale, Haynesville and Bossier Shale and EagleFord Shale consortia organized by Core Laboratories, LP. As active members in variousprofessional societies, our staff and board members also regularly interact on a professional basiswith other industry participants.

Competitive Strengths

We believe our prior success is, and our future performance will be, directly related to the followingcombination of strengths that will enable us to implement our strategies:

• High Quality Asset Base in Attractive Areas.

We have key acreage positions in active areas of the Eagle Ford and Haynesville shale plays. Webelieve our assets in these plays are characterized by low geological risk and similar repeatabledrilling opportunities that we expect will result in a predictable production growth profile. Thecommodity mix of our production and reserves is expected to become more balanced as a result ofour planned activities on our Eagle Ford and Austin Chalk acreage, which is located in oil andliquids prone areas of the plays. In addition to the Haynesville shale, our east Texas and northLouisiana assets have multiple, recognized geologic horizons, including the Middle Bossier shale,Cotton Valley and Hosston (Travis Peak) formations. We also believe there is additional resourcepotential in our oil and natural gas prospects in southeast New Mexico and west Texas, along withour natural gas prospects in southwest Wyoming and adjacent areas in Utah and Idaho.

• Large, Multi-year, Development Drilling Inventory.

Within our northwest Louisiana/east Texas and south Texas regions, we have identified 818 grossand 313 net drilling locations, including 197 gross and 157 net locations in the Eagle Ford shaleplay and 545 gross and 104 net locations in the Haynesville shale play. At September 30, 2011,these identified drilling locations included 2 gross and 2 net locations to which we have assignedproved undeveloped reserves in the Eagle Ford shale play and 95 gross and 15 net locations towhich we have assigned proved undeveloped reserves in the Haynesville shale play. We haveidentified 28 gross and 26 net locations in the Eagle Ford shale play and 25 gross and 2 netlocations in the Haynesville shale play that we expect to drill in 2012, the completion of whichwould represent approximately 14% and 5% of our identified gross drilling locations in these twoareas at September 30, 2011, respectively. Additionally, we expect to identify and developadditional locations across our broad exploration portfolio as we evaluate our Cotton Valley,Austin Chalk, Meade Peak and Delaware and Midland Basin assets. We believe our multi-year,identified drilling inventory and exploration portfolio provide visible near-term growth in ourproduction and reserves, and highlight the long-term resource potential across our asset base.

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• Financial Flexibility to Fund Expansion.

Historically, we have maintained financial flexibility by obtaining capital through shareholderinvestments and our operational cash flows while having access to additional borrowings, whichhas allowed us to take advantage of acquisition opportunities as they arise. At September 30,2011, on an as adjusted basis to give effect to this offering and our use of proceeds, we expect tohave at least $98.7 million available for borrowings under our credit agreement after giving effectto outstanding letters of credit. Excluding any possible acquisitions, we expect to maintain ourcurrent financial flexibility by funding our entire 2012 capital expenditure budget through the netproceeds we receive from this offering, together with our cash flows and future potentialborrowings under our credit agreement. As a result of our anticipated increases in production andreserves, we expect to have a sufficient increase in our cash flows from operations during the yearending December 31, 2012, as compared to our cash flows from operations in prior periods, aswell as a sufficient increase in the borrowing base under our credit agreement to help fund our2012 capital expenditure budget. A majority of our anticipated increase in cash flows during theyear ending December 31, 2012 is expected to come from our exploration activities on unprovedproperties at September 30, 2011 in the Eagle Ford shale play assuming such explorationactivities are successful. These anticipated increases in our cash flows from operations are basedupon current oil and natural gas prices and the hedges we currently have in place. If ourexploration activities result in less cash flows than anticipated, we may seek additional sources ofcapital, including through borrowings under our credit agreement (assuming availability under ourborrowing base) or from the issuance of additional equity or debt securities. In addition, we maymodify our planned capital expenditure budget for 2012 accordingly. Exploration activities aresubject to a number of risks and uncertainties that could impact our ability to sufficiently increaseour reserves, cash flows from operations and borrowing base under our credit agreement. See“Risk Factors — Our Exploration, Development and Exploitation Projects Require SubstantialCapital Expenditures That May Exceed Our Cash Flows From Operations and PotentialBorrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, WhichCould Adversely Affect Our Future Growth” and “—Drilling for and Producing Oil and NaturalGas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties ThatCould Adversely Affect Our Business.” We anticipate that we may need to access futureborrowings under our credit agreement within 30 days following completion of this offering tofund a portion of our 2012 capital expenditure requirements in excess of amounts available fromour cash flows and the net proceeds of this offering. Our availability of capital as described abovewill also allow us to maintain our competitiveness in seeking to acquire additional oil and naturalgas properties as opportunities arise. A strong balance sheet and interest savings should alsoreduce unit costs and increase profitability. In addition, since a large portion of our Eagle Fordand Haynesville acreage was held by production at September 30, 2011, we have the financialflexibility to allocate our capital when we believe it is economical and justified.

• Experienced and Incentivized Management, Technical Team and Board.

Our management and technical teams possess extensive oil and natural gas expertise with an averageof over 25 years of relevant industry experience from companies such as Matador PetroleumCorporation, S. A. Holditch & Associates, Inc., Schlumberger Limited, Conoco and ARCO, and webelieve they have a demonstrated record of growth and financial discipline over many years. Themanagement team has experience in drilling and completing hundreds of vertical and horizontalwells in unconventional resource plays, including the Cotton Valley, Bossier, Wilcox/Vicksburg,Austin Chalk, Haynesville and Eagle Ford plays. Our management team’s experience is

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complemented by a strong technical team with deep knowledge of advanced geophysical, drillingand completion technologies who are active members of their professional societies. Additionally,we have a group of board members and special advisors with considerable experience and expertisein the oil and natural gas industry and in managing other successful enterprises who provide insightand perspective regarding our business and the evaluation, exploration, engineering anddevelopment of our prospects. In addition to its considerable experience, our management teamcurrently owns and will continue to own a significant direct ownership interest in us immediatelyfollowing the completion of this offering. We believe our management team’s direct ownershipinterest, as well as their ability to increase their holdings over time through our long-term incentiveplan, aligns management’s interests with those of our shareholders.

• Extensive Geologic, Engineering and Operational Experience in Unconventional Reservoir Plays.

The individuals on our technical team are highly experienced in analyzing unconventionalreservoir plays and in horizontal drilling, completion and production operations in a number ofgeographic areas. Our geologists have extensive experience in analyzing unconventional reservoirplays throughout the United States, including our principal areas of interest, by using the latestimaging technology, such as 2-D and 3-D seismic interpretation, and petrophysical analysis. Inaddition, our technical team has been directly involved in over 26 different horizontal well drillingand/or operations programs in both onshore and offshore formations located in the United Statesand abroad. Our team’s diverse and broad horizontal drilling experience includes most, if not all,techniques used in modern day drilling. Additionally, our team has in-depth experience withvarious horizontal completion techniques and their applications in various unconventional plays.We intend to leverage our team’s geological expertise and horizontal drilling and completionexperience to develop and exploit our large, multi-year development drilling inventory.

• Multi-Disciplined Approach to New Opportunities.

Our process for evaluating and developing new oil and natural gas prospects is a result of what webelieve is an organizational philosophy that is dedicated to a systematic, multi-disciplinaryapproach to new opportunities with an emphasis on incorporating petroleum systems,geosciences, technology and finance into the decision-making process. We recognize theimportance of consulting multiple individuals in our organization across all disciplines and alllevels of responsibility prior to making exploration, acquisition or development decisions and theformulation of key criteria for successful exploration and development projects in any given playto enhance our decision-making. We also conduct a post-completion review of our majordecisions to determine what we did right and where we need to improve. At times, this approachresults in a decision to accelerate our drilling program or expand our positions in certain areas.Other times, this approach results in a decision to mitigate risk associated with our explorationand development programs by sharing operational risks and costs with other industry participantsor exiting an area altogether. We believe this multi-disciplined approach underpins our trackrecord of value creation and represents the best way to deliver consistent, year-over-year results toour shareholders.

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Recent Developments

Recent Results

At January 16, 2012, we had drilled an aggregate of 11 Eagle Ford horizontal wells as operator. Sevenof these wells have been completed and are producing. One of these wells, the Martin Ranch #8H in LaSalle County, Texas, is currently undergoing completion operations, and we anticipate that two additionalwells, the Martin Ranch #6H and the Martin Ranch #7H, will be completed in the near future. The MatadorSickenius ORCA #1H in Karnes County, Texas is also expected to be completed during the first quarter of2012. At January 16, 2012, we had two contracted drilling rigs operating in the Eagle Ford play: one in LaSalle County and the second in Karnes County.

For the month of December 2011, our daily production averaged approximately 43.4 MMcfe per day,including 39.8 MMcf of natural gas per day and 600 Bbl of oil per day. During the first 11 days of January2012, our daily production averaged approximately 53.2 MMcfe per day, including 42.4 MMcf of naturalgas per day and 1,800 Bbl of oil per day.

In December 2011, four of our Eagle Ford wells, the Martin Ranch #2H, #3H and #5H in La SalleCounty, Texas and the Lewton #1H in DeWitt County, Texas, began producing. In January 2012, weestimated that these four wells and six associated proved undeveloped locations increased our proved oiland natural gas reserves by approximately 2.8 million barrels of oil and 4.2 Bcf of natural gas as ofDecember 31, 2011. These incremental estimates of proved reserves were prepared by our engineering staffand have been reviewed for reasonableness by Netherland, Sewell & Associates, Inc., our independentreservoir engineers. These estimates were determined in accordance with guidelines established by theSecurities and Exchange Commission for estimating and reporting oil and natural gas reserves. At January16, 2012, we had not yet completed the estimates of our proved oil and natural gas reserves for theremainder of our properties at December 31, 2011.

Other Developments

Between November 2011 and January 2012, we entered into various costless collars to mitigate ourexposure to oil price volatility and enhance predictability of our cash flows in 2012 and 2013. As ofJanuary 13, 2012, we have hedged a total of 1,060,000 Bbl of oil for 2012 and a total of 780,000 Bbl of oilfor 2013. For 2012, all collars have a price floor of $90.00/Bbl and price ceilings that range from$104.20/Bbl to $113.75/Bbl. For 2013, all collars have price floors of $85.00/Bbl or $90.00/Bbl and priceceilings that range from $102.25/Bbl to $110.40/Bbl. These costless collars may limit our potential gains ifoil prices rise above the specified price ceilings. For additional information, see “Risk Factors—HedgingTransactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in Financial Losses”and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Exposure.”

In December 2011, we amended and restated our senior secured revolving credit agreement. Thisamendment increased the maximum facility amount from $150 million to $400 million. Borrowings arelimited to the lesser of $400 million or the borrowing base, which will be $100 million immediately followingthis offering. On January 25, 2012, we borrowed an additional $10.0 million under this agreement whichbrought our total borrowings to $123.0 million.

In November and December 2011, we completed three additional operated Eagle Ford horizontalwells, the Martin Ranch #2H, #3H and #5H in northeastern La Salle County, Texas. During initial flowtests on these wells, the Martin Ranch #2H tested at approximately 1,310 Bbls of oil and 1.8 MMcf of

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natural gas per day, the Martin Ranch #3H tested at approximately 620 Bbls of oil and 0.5 MMcf of naturalgas per day, and the Martin Ranch #5H tested at approximately 810 Bbls of oil and 0.6 MMcf of natural gasper day. All three wells were turned to sales in late December 2011. We are the operator and have a 100%working interest in these three wells.

In August 2011, we completed our fourth operated Eagle Ford horizontal well, the Lewton #1H inDeWitt County, Texas. This well began producing to sales in late December 2011, and in early January2012, the well was producing at approximately 2.7 MMcf of natural gas and 600 Bbls of condensate per dayduring an initial flow test and began producing to sales in late December 2011. We are the operator of thiswell and paid 100% of the costs to drill and complete the well. We will receive 85% of the revenuesattributable to the working interest in the well until we have recovered all of our acquisition, drilling andcompletion costs, after which time, our partner will receive 50% of the revenues attributable to the workinginterest in the well and we and our partner will each maintain a 50% working interest in the well.

Between March and July 2011, we acquired leasehold interests in approximately 6,300 gross and 4,800net acres in DeWitt, Karnes, Wilson and Gonzales Counties, Texas in the Eagle Ford shale play from OrcaICI Development, JV. We believe that all of this acreage is in an oil and liquids prone area of the EagleFord play. We believe that the acreage in Wilson and Gonzales Counties and a portion of DeWitt Countywill be prospective for oil and liquids from the Austin Chalk formation in addition to the Eagle Ford. Wepaid approximately $31.5 million to acquire this acreage. We currently own a 50% working interest in theacreage (approximately 2,800 gross and 1,400 net acres) in DeWitt County and are the operator. Wecurrently own a 100% working interest in the acreage (approximately 3,500 gross and 3,400 net acres) inKarnes, Wilson and Gonzales Counties and are the operator.

In March 2011, first sales of natural gas began from our Williams 17 H#1 well, located in what webelieve to be the core area of the Haynesville shale play in northwest Louisiana. We began producing thiswell at a constrained rate of about 10.0 MMcf of natural gas. During November 2011, this well produced atan average daily rate of 4.5 MMcf of natural gas per day, and through November 30, 2011, had producedapproximately 1.7 Bcf of natural gas. We are the operator and have a 100% working interest and a favorable87.5% net revenue interest in this well.

In February 2011, we completed our third operated Eagle Ford horizontal well, the Affleck #1H, ineastern Dimmit County, Texas. This well tested at approximately 415 Bbls of oil and 5.4 MMcf of naturalgas per day during an initial flow test. During November 2011, this well produced at an average daily rateof 0.9 MMcf of natural gas and 70 Bbls of oil per day. We are the operator and have a 100% workinginterest in this well.

In January 2011, we completed a private placement offering of 1,922,199 shares of our Class Acommon stock at $11.00 per share for an aggregate amount of $21,144,189.

In January 2011, we completed our second operated Eagle Ford horizontal well, the Martin Ranch#1H, in northeastern La Salle County, Texas. First sales of oil and natural gas from this well began in lateMarch at approximately 700 Bbls of oil and 350 Mcf of natural gas per day. During November 2011, thewell produced at an average daily rate of approximately 520 Bbls of oil and 0.6 MMcf of natural gas perday, and through November 30, 2011, had produced a total of approximately 111,000 Bbls of oil and 135MMcf of natural gas. We are the operator and have a 100% working interest in this well.

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In January 2011, first sales of oil and natural gas began from our first operated Eagle Ford horizontalwell, the JCM Jr. Minerals #1H, in southern La Salle County, at approximately 3.4 MMcf of natural gas and135 Bbls of condensate per day. During November 2011, the well produced at an average daily rate ofapproximately 0.6 MMcf of natural gas and 12 Bbls of condensate per day, and through November 30,2011, had produced a total of approximately 416 MMcf of natural gas and 10,900 Bbls of condensate. Weare the operator and have a 100% working interest in this well.

In January 2011, we completed our first horizontal Cotton Valley well, the Tigner Walker H#1-Alt., inDeSoto Parish, Louisiana. First sales of natural gas from this well began in late January at approximately4.6 MMcf of natural gas per day. During November 2011, the well produced at an average daily rate ofapproximately 1.9 MMcf of natural gas per day, and through November 30, 2011, had produced a total ofapproximately 900 MMcf of natural gas. We are the operator and have a 100% working interest in this wellsubject to a reversionary interest at payout.

On December 31, 2010, first sales of natural gas began from our L.A. Wildlife H#1 Alt. horizontalwell, located in what we believe to be the core area of the Haynesville shale play in northwest Louisiana.We began producing this well at a constrained rate of about 10.0 MMcf of natural gas per day. DuringNovember 2011, the well produced at an average daily rate of approximately 10.0 MMcf of natural gas perday, and through November 30, 2011, had produced a total of approximately 3.2 Bcf of natural gas. We arethe operator and have a 95% working interest in this well.

Other Significant Prior Events

Chesapeake Transaction

In July 2008, we consummated a transaction with a subsidiary of Chesapeake Energy Corporation forthe sale of the deep rights underlying the acreage in our Elm Grove/Caspiana properties in southern CaddoParish, Louisiana. We retained a carried interest in the initial well drilled in each of the sections in which weheld leases. The deep rights were below the depth of any producing wells previously drilled by us andrepresented primarily the rights to explore for and develop the Haynesville shale underlying the CottonValley formation that was producing from the wells in our Elm Grove/Caspiana properties. The deep rightsassigned to Chesapeake also included the Middle Bossier shale formation located between the base of theCotton Valley formation and the top of the Haynesville shale. At the time of the Chesapeake transaction, wehad no production from and no reserves assigned to the Haynesville shale play. We retained all rights tothose depths above the base of the Cotton Valley formation, as well as all existing and future production andreserves from those formations. We reserved the right to be reassigned a proportionately reduced 25%working interest in each well drilled to the Haynesville shale by Chesapeake in each regular spacing unitestablished for the Haynesville shale which includes any of the rights we previously assigned toChesapeake. Chesapeake agreed to carry us for all of the drilling and completion costs attributable to ourinterest in the first well drilled in each Haynesville spacing unit. In addition, we have the right to participatein subsequent wells drilled in each such spacing unit to the Haynesville shale on the basis of aproportionately reduced 25% non-carried working interest. We also reserved an overriding royalty interestin certain of the deep rights that were sold. At September 30, 2011, Chesapeake had paid all of our costs fordrilling and completing 22 gross wells to the Haynesville shale, and we will have a carried interest in twoadditional gross wells that we expect will be completed before the end of 2011.

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Stroud Transaction

In August 2009, we acquired from Stroud Exploration Company, L.L.C. and Stroud Petroleum, Inc.95% of the deep rights below the base of the Cotton Valley formation underlying approximately 600 acresprospective for the Haynesville shale play to the immediate southwest of our Elm Grove/Caspiana acreage.We also took title to an existing vertical Haynesville well that was holding this acreage by production. Wewere obligated to reassign this vertical Haynesville well to Stroud following the completion of our firsthorizontal Haynesville well drilled on this acreage, at which time, Stroud would recomplete this verticalwell in the Cotton Valley formation. On December 31, 2010, first sales of natural gas began from our L.A.Wildlife H #1 Alt. well, the first Haynesville horizontal well that we drilled on this acreage. We beganproducing this well at a constrained rate of about 10.0 MMcf of natural gas per day. During November2011, the well produced at an average daily rate of approximately 10.0 MMcf of natural gas per day, andthrough November 30, 2011, had produced a total of approximately 3.2 Bcf of natural gas. We are theoperator and have a 95% working interest in this well. In March 2011, we reassigned the vertical well toStroud Exploration, reserving our rights below the base of the Cotton Valley formation.

Alliance Capital Participation Agreement

In May 2010, Roxanna Rocky Mountains, LLC and Alliance Capital Real Estate, Inc., an affiliate ofAllianceBernstein L.P., entered into a participation agreement with our subsidiary, MRC Rockies Company,or MRC Rockies, regarding our Meade Peak shale prospect in southwest Wyoming and adjacent areas inUtah and Idaho. Under this agreement, Alliance Capital Real Estate agreed to pay up to $4.2 million of thecost to drill and core an initial test well in the Meade Peak shale and MRC Rockies agreed to pay up to anadditional $630,000 to conclude such operations, if necessary. Each entity has agreed to pay 50% of anycosts over $4.83 million for the initial test well. Roxanna Rocky Mountains elected to participate for up to a10% working interest in the initial test well with the costs for its working interest to be carried by MRCRockies. The 10% carried working interest participation by Roxanna Rocky Mountains in the initial testwell was assigned from MRC Rockies’ 50% working interest in the leases within the 5,760 gross acresaround the drill site.

After receipt of the laboratory analysis of the whole core data from the initial test well, AllianceCapital Real Estate has the option to purchase up to a 50% working interest in the balance of all the leasesin the prospect owned by MRC Rockies, to elect to drill and complete a second test well in the prospect atan agreed upon location or to elect not to proceed with further exploration of the prospect. If it elects to drilla second test well, it will pay up to $5.0 million of the costs to drill and complete, and to perform aproduction test on, the well. Each entity will pay 50% of any costs over $5.0 million. After drilling andproduction testing the second test well, Alliance Capital Real Estate has a second option to purchase up to a50% working interest in the balance of the leases owned by MRC Rockies in the prospect. If AllianceCapital Real Estate elects to drill a second test well, Roxanna Rocky Mountains will have a similar option toparticipate for up to a 10% carried working interest in the second test well, which will be assigned fromMRC Rockies’ 50% working interest in the leases within the 5,760 gross acres around the second drill site.If Roxanna Rocky Mountains elects not to participate in the second test well, Roxanna Rocky Mountainswill relinquish all of its rights in the leases within the 5,760 gross acres around the second drill site, otherthan its reserved 2.5% overriding royalty interest.

Roxanna Rocky Mountains will bear and pay its proportional working interest share of all leasemaintenance costs on these two test wells and has the right to participate and pay its proportional workinginterest share of all costs, on a well-by-well basis, in the drilling of any subsequent well proposed to be

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drilled on the prospect, except that Roxanna Rocky Mountains will not have the right to participate in the5,760 acres around any second test well if it relinquishes its working interest in the leases in that areabecause it elects not to participate.

The parties also agreed to a large area of mutual interest for the prospect over a 10-year period. Alloperations in the prospect are governed by the terms of a joint operating agreement, with the parties bearingtheir respective working interest shares of the costs of any subsequent wells drilled on the prospect after thefirst two test wells. All working interests owned by the parties in the prospect will be subject to aproportionally reduced 2.5% overriding royalty interest owned by Roxanna Rocky Mountains in the leases.We will be the operator of the first two test wells, if both are drilled, and are the operator for the projectunder the joint operating agreement. We began drilling the initial test well, the Crawford Federal #1 well inLincoln County, Wyoming, in February 2011. We reached a depth of 8,200 feet, approximately 300 feetabove the top of the Meade Peak shale, before having operations suspended for several months due towildlife restrictions. We resumed operations on this initial test well in September 2011 and completeddrilling and coring operations on this well in November 2011.

Acquisition of Bureau of Land Management Leases

In July 2010, we acquired approximately 850 gross and net acres in northwest Louisiana under twoseparate leases taken from the U.S. Bureau of Land Management that are primarily prospective for both theHaynesville and Middle Bossier shale plays. These leases have a ten-year primary term and a 12.5%lessor’s royalty. As part of the acquisition, we acquired the rights to one complete, approximately 640-acre,section in which we have a 100% working interest and are the operator. In March 2011, first sales of naturalgas began from our Williams 17 H#1 well located in this section which we believe is in the core area of theHaynesville shale play. We began producing this well at a constrained rate of about 10.0 MMcf of naturalgas per day. During November 2011, the well produced at an average rate of approximately 4.5 MMcf ofnatural gas per day and, through November 30, 2011, had produced approximately 1.7 Bcf of natural gas.We are the operator and have a 100% working interest in this well.

Glasscock Ranch Acquisition

On December 1, 2010, we acquired leasehold interests in approximately 8,900 gross and net acres insoutheast Zavala County, Texas in the Eagle Ford shale play. We currently anticipate that this area of theEagle Ford shale play will be predominantly prospective for oil and liquids. This acreage is also prospectivefor oil and liquids from other formations including the shallower Austin Chalk formation. We paidapproximately $31.5 million to acquire this acreage. We own a 100% working interest in this property andare the operator.

Principal Areas of Interest

Our focus since inception has been the exploration for oil and natural gas in unconventional resourceplays with a particular focus over the last few years in the Haynesville shale play and more recently in theEagle Ford shale play. Our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zonecompletions. We have also sought to balance the risk profile of our prospects, as well as to explore for moreconventional targets in addition to the unconventional resource plays.

At December 2011, our principal areas of interest consist of (1) the Eagle Ford shale play in southTexas, (2) the Haynesville shale play, including the Middle Bossier shale play, as well as the traditional

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Cotton Valley and Hosston (Travis Peak) formations in northwest Louisiana and east Texas, (3) the MeadePeak shale play in southwest Wyoming and the adjacent areas of Utah and Idaho and (4) southeast NewMexico and west Texas, including the Delaware and Midland Basins.

South Texas

Eagle Ford Shale and Other Formations

The Eagle Ford shale extends across portions of south Texas from the Mexican border into east Texasforming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically richcalcareous shale, in places transitioning to an organic, argillaceous lime-mudstone. It lies between thedeeper Buda limestone and the shallower Austin Chalk formation. Most, if not all, of the oil found in theAustin Chalk and Buda formations is generally believed to be sourced from the Eagle Ford shale. In theprospective areas for the Eagle Ford shale, the interval averages 200 feet thick, is found at depths rangingfrom as shallow as 4,000 feet to as deep as 13,000 feet, and in much of the deeper portions of the play isoverpressured. The Eagle Ford shale has a total organic carbon content of 1% to 7% that is comparable tothe Haynesville shale, and is generally porous, with core-measured porosities ranging between 4% and 14%.

Along the entire length of the Eagle Ford trend the structural dip of the formation is consistently downto the south with relatively few, modestly sized structural perturbations. As a result, depth of burialincreases consistently southwards along with the thermal maturity of the formation. Where the formation isshallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes morethermally mature, the Eagle Ford shale is more natural gas prone. The transition between being more oilprone and more natural gas prone includes an interval that typically produces wet gas with condensate. Webelieve that almost 85% of our Eagle Ford acreage lies within those portions of the Eagle Ford shale that areprone to produce oil or wet gas with condensate.

Most of the current Eagle Ford shale activity is concentrated in Atascosa, Bee, DeWitt, Dimmit, Frio,Gonzales, Karnes, La Salle, Lavaca, Live Oak, Maverick, McMullen, Webb, Wilson and Zavala Counties insouth Texas. The first horizontal wells drilled specifically for the Eagle Ford shale were drilled in 2008,leading to a discovery in La Salle County. Since then, the play has expanded significantly across a largeportion of south Texas.

Public information indicates that operators are typically drilling 3,500 to 7,000 feet horizontal lateralsand applying hydraulic fracture stimulation in multiple stages along the full length of the horizontal lateralsto complete the wells and establish production. Although production rates vary across the different areas ofthe play, initial production rates in the oil areas have been reported as high as 1,000 to 1,500 Bbls of oil perday with varying amounts of associated natural gas. In the natural gas areas of the Eagle Ford play, initialproduction rates as high as 5.0 to 15.0 MMcfe per day have been reported with varying amounts ofassociated oil and liquids.

At September 30, 2011, our aggregate leasehold interests consisted of approximately 52,000 grossacres and 29,000 net acres in the Eagle Ford shale play in Atascosa, DeWitt, Dimmit, Karnes, La Salle,Gonzales, Webb, Wilson and Zavala Counties in south Texas. We believe portions of this acreage are alsoprospective for the Austin Chalk, Buda, Olmos and other formations, from which we expect to producepredominantly oil and liquids. In particular, the Austin Chalk formation, which is a naturally fracturedcarbonate ranging in thickness from 200 to 400 feet, has produced from several fields on or nearby portionsof our acreage. Our Zavala County acreage, for example, is located within the historic Pearsall (AustinChalk) field.

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We believe that almost 85% of our Eagle Ford acreage is prospective predominantly for oil and liquids.We expect to use a portion of the net proceeds we receive from this offering to explore and develop thisacreage and to acquire additional acreage in south Texas as we seek to actively grow the oil and liquidscomponent of our production and reserves. We currently own a 100% working interest in approximately26,000 gross acres and 23,000 net acres in Dimmit, Gonzales, Karnes, La Salle, Webb, Wilson and ZavalaCounties and a 50% working interest in approximately 2,800 gross and 1,400 net acres in DeWitt Countyand are the operator of this acreage. We also own an approximate 21% working interest in approximately23,000 gross acres in Atascosa County operated by EOG Resources, Inc. At September 30, 2011,approximately 80% of our Eagle Ford acreage is either held by production or not burdened by leaseexpirations before 2013.

At January 16, 2012, we had drilled and completed seven Eagle Ford wells on our operated properties,and all of these wells are producing to sales. At that date, we had also participated in two Eagle Ford wellswith EOG Resources, Inc. as operator, on the Atascosa County acreage. Our first operated Eagle Fordhorizontal well, the JCM Jr. Minerals #1H in southern La Salle County along the Edwards Reef, wascompleted in November 2010. First sales of oil and natural gas began from this well in late January 2011, andduring November 2011, the well produced at an average daily rate of approximately 0.6 MMcf of natural gasand 12 Bbls of condensate per day. Our second operated Eagle Ford horizontal well, the Martin Ranch #1H innortheastern La Salle County, was completed in January 2011 and tested approximately 1,200 Bbls of oil perday during an initial flow test. First sales of oil and natural gas from this well began in late March atapproximately 700 Bbls of oil and 350 Mcf of natural gas per day. During November 2011, the well producedat an average daily rate of approximately 520 Bbls of oil and 0.6 MMcf of natural gas per day. Our thirdoperated Eagle Ford horizontal well, the Affleck #1H, was completed in February 2011 in eastern DimmitCounty, Texas, and tested at approximately 415 Bbls of oil and 5.4 MMcf of natural gas per day during aninitial flow test. During November 2011, the well produced at an average daily rate of 0.9 MMcf of natural gasand 70 Bbls of oil per day. In August 2011, we completed our fourth operated Eagle Ford horizontal well, theLewton #1H in DeWitt County, Texas. This well began producing to sales in late December 2011, and in earlyJanuary 2012, the well was producing at approximately 2.7 MMcf of natural gas and 600 Bbls of condensateper day.

In November and December 2011, we completed three additional operated Eagle Ford horizontal wells,the Martin Ranch #2H, #3H and #5H in northeastern La Salle County, Texas. During initial flow tests onthese wells, the Martin Ranch #2H tested at approximately 1,310 Bbls of oil and 1.8 MMcf of natural gas perday, the Martin Ranch #3H tested at approximately 620 Bbls of oil and 0.5 MMcf of natural gas per day, andthe Martin Ranch #5H tested at approximately 810 Bbls of oil and 0.6 MMcf of natural gas per day. All threewells were turned to sales in late December 2011. As we are in the initial stages of our Eagle Ford operations,we have only a small amount of production and proved reserves attributable to this acreage.

Between March and July 2011, we acquired leasehold interests in approximately 6,300 gross and 4,800net acres in DeWitt, Karnes, Wilson and Gonzales Counties, Texas in the Eagle Ford shale play from OrcaICI Development, JV. We paid approximately $31.5 million to acquire this acreage. We currently own a50% working interest in the acreage (approximately 2,800 gross and 1,400 net acres) in DeWitt County andare the operator. We currently own a 100% working interest in the acreage (approximately 3,500 gross and3,400 net acres) in Karnes, Wilson and Gonzales Counties and are the operator.

We will pay 100% of the costs to drill and complete the first six wells drilled on the acreage in DeWittCounty. We will have an 85% working interest in these six wells until we have recovered all of ouracquisition, drilling and completion costs from each well, at which time Orca’s working interest will

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increase to 50%. When the cumulative production from each of the first six wells reaches 500,000 BOE, ona well-by-well basis, then Orca’s working interest in that well increases to 55%. If the cumulativeproduction from each of the first six wells reaches 750,000 BOE, on a well-by-well basis, then Orca’sworking interest in that well will increase to 70%. Both we and Orca will own a 50% working interest in allsubsequent wells drilled after the first six wells on the acreage in DeWitt County.

We will have a 100% working interest in the first five wells drilled on the acreage in Karnes, Wilson andGonzales Counties. When we have recovered all of our acquisition, drilling and completion costs from each ofthese five wells, Orca may elect, on a well-by-well basis, to back-in for a 25% working interest in these wells.In addition, Orca retains a one-time election for a short period of time after we complete these first five wellsto participate for a 25% working interest in all subsequent wells drilled on this acreage by paying a purchaseprice equal to 25% of our costs to acquire the acreage in Karnes, Wilson and Gonzales Counties.

In addition to the Eagle Ford potential on our acreage, we believe that approximately 24,000 grossacres and 15,000 net acres in south Texas are prospective primarily for the Austin Chalk formation, whichhas historically been targeted by operators in south Texas. We have not yet drilled an Austin Chalk well,and although we believe that other prospective well locations exist on this acreage, we have only included16 gross and net well locations in our total identified drilling locations at September 30, 2011.

Northwest Louisiana and East Texas

Most of our current production and proved reserves is attributable to our acreage in northwestLouisiana and east Texas. For the nine months ended September 30, 2011 about 76% of our dailyproduction, or 32.1 MMcfe per day, was produced from the Haynesville shale, with another 16%, or7.0 MMcfe per day, produced from the Cotton Valley and other shallower formations in this area. AtSeptember 30, 2011, approximately 84% of our proved reserves, or 136.6 Bcfe, was attributable to theHaynesville shale underlying this acreage with another 10% of our proved reserves, or 16.1 Bcfe, associatedwith the Cotton Valley and shallower formations. In addition, we are evaluating the Bossier shale playwhich is generally encountered above the Haynesville shale and below the Cotton Valley formation.

We operate all of our Cotton Valley and shallower production under this acreage, as well as all of ourHaynesville production on the acreage outside of what we believe to be the core area of the Haynesvilleplay. Of the approximately 5,500 net acres that we consider to be in the core area of the Haynesville play,we operate about 22% of that acreage.

Haynesville and Middle Bossier Shales

The Haynesville shale is an organically rich, overpressured marine shale found below the CottonValley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500feet across a broad region throughout northwest Louisiana and east Texas, including principally Bossier,Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties inTexas. The Haynesville shale has a typical thickness ranging from 100 to 300 feet. Total organic carbonranges from 0.5% to 5.0%, with core-measured porosities from 3% to 15%. The Haynesville shale producesprimarily dry natural gas with almost no associated liquids.

The oil and natural gas industry has focused significant attention on the Haynesville shale play over thelast three years, and the play is currently one of the most active and economically viable in the UnitedStates. Operators are typically drilling 4,500 to 5,000 feet horizontal laterals and applying hydraulic fracturestimulation in multiple stages along the entire length of the horizontal laterals to complete the wells and

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establish production. Although initial production rates vary widely across the play, initial production ratesas high as 20.0 to 25.0 MMcf per day of natural gas have been reported by operators from horizontal wellsdrilled and completed in the Haynesville shale.

The Bossier shale is overpressured and is often divided into lower, middle and upper units. The MiddleBossier shale appears to be productive for natural gas under large portions of DeSoto, Red River and SabineParishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similarproductive characteristics to the deeper Haynesville shale. Typically, the Middle Bossier shale is found atdepths ranging from 500 to 800 feet shallower than the Haynesville shale, has a typical thickness ranging from150 to 300 feet, has core-measured porosities ranging between 5% and 14%, and total organic carbon valuesbetween 0.5% and 4%. Although there is some overlap between the Bossier and Haynesville shale plays, thetwo plays appear quite distinct and a separate horizontal wellbore is typically needed for each formation.

We have leasehold and mineral interests in approximately 23,000 gross and 15,000 net acresprospective for the Haynesville shale. Portions of our acreage are located in Caddo, DeSoto, Bossier andRed River Parishes, Louisiana and in Harrison County, Texas. This acreage includes just over 5,500 netacres in what we believe is the core area of the play. Just over 90% of our Haynesville acreage is held byproduction and portions of it are also producing from and, we believe, prospective for the Cotton Valley,Hosston (Travis Peak) and other shallower formations. In addition, we believe that approximately 1,700 netacres are prospective for the Middle Bossier play as well. We have not yet drilled a Middle Bossier shalewell, and although we believe that prospective well locations exist on this acreage, we have not yet includedany Middle Bossier locations in our identified drilling locations at September 30, 2011.

Within the 5,500 net acres that we believe to be in the core area of the Haynesville shale play, we arethe operator in two sections where we have working interests of 95% and 100% in all wells to be drilled. InOctober 2010, as operator, we drilled and completed our L.A. Wildlife H #1 horizontal Haynesville well inthe section in which we have a 95% working interest and on December 31, 2010 first sales of natural gasbegan from this well. During November 2011, the well produced at an average daily rate of approximately10.0 MMcf of natural gas per day, and through November 30, 2011, had produced a total of approximately3.2 Bcf of natural gas. In March 2011, we completed our operated Williams 17 H #1 horizontal Haynesvillewell on the second section where we have a 100% working interest. During November 2011, this wellproduced at an average daily rate of 4.5 MMcf of natural gas per day and, through November 30, 2011, hadproduced approximately 1.7 Bcf of natural gas. We began producing both of these wells at a constrainedrate of about 10.0 MMcf of natural gas per day. We have identified 12 gross and approximately 12 netpotential additional Haynesville locations that we may drill and operate in the future in these two sections.

The remainder of our acreage in the core area of the Haynesville shale play, about 4,300 net acres, isoperated by other companies. As described above in “Business—Other Significant Prior Events—ChesapeakeTransaction,” just over half of our non-operated Haynesville acreage in this area of the play results from ourtransaction with Chesapeake in July 2008. The remainder of our non-operated Haynesville acreage isattributable to leasehold interests that we hold in approximately 87 sections in Caddo, DeSoto, Bossier andRed River Parishes. Our working interests in the Haynesville wells in these sections range from less than 1%to more than 30%. At September 30, 2011, we were participating in 90 non-operated Haynesville wells withChesapeake and other operators, including producing wells and wells being drilled and completed at that time.At September 30, 2011, our production from these wells averaged approximately 19 MMcfe per day.

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Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations

Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of ourproduction and reserves in northwest Louisiana and east Texas were attributable to wells producing fromthe Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valleyformation to the surface under our acreage in northwest Louisiana and east Texas.

All of the shallow rights underlying our acreage in our Elm Grove/Caspiana properties in northwestLouisiana, approximately 10,000 gross and net acres, is held by existing production from the Cotton Valleyformation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in theElm Grove field prior to discovery of the Haynesville shale. The Cotton Valley formation is a lowpermeability gas sand that ranges in thickness from 200 to 300 feet and has porosites ranging from 6% to10%.

In January 2011, we completed our first horizontal Cotton Valley well, the Tigner Walker H #1-Alt. inour Elm Grove/Caspiana properties, in DeSoto Parish and commenced sales of natural gas from this well.Prior to this time, we had only drilled and completed vertical Cotton Valley and Hosston wells on theseproperties. During November 2011, this well produced at an average daily rate of approximately 1.9 MMcfof natural gas per day and through November 30, 2011, had produced a total of approximately 900 MMcf ofnatural gas. We are the operator and have a 100% working interest in this well. We have identified 60 grossand 36 net additional drilling locations for future Cotton Valley horizontal wells in our Elm Grove/Caspianaproperties. We do not plan to drill any of these locations in 2012. As all of this acreage is held by existingproduction, we expect to allocate our near-term capital expenditures primarily to exploration anddevelopment of our Eagle Ford shale acreage in south Texas and to additional exploration and developmentof our Haynesville acreage in northwest Louisiana.

We also continue to hold the shallow rights by existing production or by leases that are still in theirprimary terms in our central and southwest Pine Island, Longwood, Woodlawn and other prospect areas innorthwest Louisiana and east Texas. We hold an estimated 11,500 net leasehold and mineral acres byexisting production in these areas.

Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale

The Meade Peak shale is an organic-rich source rock that has sourced much of the oil and natural gasin conventional reservoirs in the western Wyoming and eastern Utah area. The Meade Peak shale has anobserved shale thickness of 70 to 350 feet, total organic carbon of 3% to 7%, and vitrinite reflectance valuesranging from 1.8% to 2.7%. The Meade Peak shale is encountered at drill depths of 3,000 to 14,000 feet,with the majority of our acreage in the depth range of 3,000 to 10,000 feet. The shale has been penetrated byover 100 wells in the area, most of which have natural gas shows. Seismic and subsurface data showdistinct, stacked thrust plates with areas of sediment prospective for natural gas.

Together with our joint venture partner, Roxanna Rocky Mountains, LLC, we have assembledapproximately 144,000 gross, or approximately 136,000 net, acres in southwest Wyoming and adjacentareas in Utah and Idaho as part of a natural gas shale exploratory prospect targeting the Meade Peak shale.The majority of this acreage, with lease terms of 5 to 10 years, has been acquired by us within the past fouryears, and we are the operator of this prospect. We have no production and no proved reserves attributableto this acreage at September 30, 2011.

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We believe there have been no previous attempts to drill horizontally or to hydraulically fracture theMeade Peak shale in this area. Our focus to date has been to confirm the structure of the Meade Peak shale,understand its characteristics and evaluate its potential. We have gathered well log data in the area andstudied the petrophysical characteristics. In addition, we have purchased 2-D seismic data and have workedwith a structural geologist that has experience in the immediate area to better understand the area’s tectonichistory.

As described in “Business — Other Significant Prior Events — Alliance Capital ParticipationAgreement,” we are the operator of this prospect and have entered into a participation and joint operatingagreement with other parties covering the initial exploration efforts and, if successful, the futuredevelopment of this acreage. We began drilling the initial test well on this prospect, the Crawford Federal#1 well in Lincoln County, Wyoming, in February 2011. We reached a depth of 8,200 feet, approximately300 feet above the top of the Meade Peak shale, before having operations suspended for several months dueto wildlife restrictions. We resumed operations on this initial test well in September 2011 and completeddrilling and coring operations on this well in November 2011.

Southeast New Mexico and West Texas — Delaware and Midland Basins

The Delaware and Midland Basins are mature exploration and production provinces with extensivedevelopments in a wide variety of petroleum systems resulting in stacked target horizons in manyareas. Historically, the majority of development in these basins has focused on relatively conventionalreservoir targets, but we believe the combination of advanced formation evaluation, 3D seismic technology,horizontal drilling and hydraulic fracturing technology is enhancing the development potential of thesebasins.

One example of such an opportunity appears to be the so-called “Wolf-Bone” play of the DelawareBasin. Together, the Lower Permian age Bone Spring (also called Leonardian) and Wolfcamp formationsspan several thousand feet of stacked shales, sandstones, limestones and dolomites representing complexand dynamic submarine depositional systems that include several organic rich source rocks. Throughoutthese intervals, oil and natural gas have been produced primarily from conventional sandstone andcarbonate reservoirs even though hydrocarbons are trapped in the tight sands, limestones and dolomitesinterbedded within organic rich shale. Recently, these hydrocarbon-bearing zones have been recognized bya number of operators as targets for horizontal drilling and multi-stage hydraulic fracturing techniques. As aresult, several large industry players are expanding positions and conducting drilling programs throughoutLea and Eddy Counties in southeast New Mexico and Loving, Reeves and Ward Counties in west Texas.

Although the Delaware and Midland Basins have not been a primary focus of our recent operations orexploration efforts, we are currently developing new oil and natural gas prospects in these basins. Mostnotably, we have identified potential drilling opportunities on our acreage, particularly in southeast NewMexico, near old vertical wells, some of which have produced up to 1,000,000 BOE from the Wolfcampformation and up to 500,000 BOE from the Bone Spring formation. These wells suggest a hydrocarbon-richenvironment in the area of our acreage, and after completing our internal geologic studies, we maydetermine to drill a Wolfcamp or Bone Spring vertical well or to drill a horizontal well to test theseformations on our acreage. At September 30, 2011, we had not included any potential drilling locations onour acreage in our total identified drilling locations, and we had not budgeted any capital expenditures todrill wells in southeast New Mexico or west Texas during 2012. We have budgeted $20.0 million of ouranticipated 2012 capital expenditures to acquire additional leasehold interests primarily prospective for oiland liquids production in areas of southeast New Mexico and west Texas where we are developing new

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prospects. Although we do have existing leasehold interests in this area, we believe approximately 7,700gross and 4,900 net acres are no longer prospective, and we plan to let them expire without drilling.

Operating Summary

The following table sets forth certain unaudited production data for the years ended December 31,2010, 2009 and 2008 and the nine months ended September 30, 2011 and 2010:


September 30,

2010 2009 2008 2011 2010

Unaudited Production Data

Net Production Volumes:

Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 30 37 113 24Natural gas (Bcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4 4.8 3.1 10.9 5.9

Total natural gas equivalents (Bcfe)(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.6 5.0 3.3 11.6 6.0Average daily production (MMcfe/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23.6 13.7 9.0 42.5 22.0

Average Sales Prices:Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $76.39 $57.72 $98.59 $92.71 $74.59Natural gas, with realized derivatives (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4.38 $ 5.17 $ 8.32 $ 4.19 $ 4.49Natural gas, without realized derivatives (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . $ 3.75 $ 3.59 $ 8.75 $ 3.80 $ 3.98

Operating Expenses (per Mcfe):

Production taxes and marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.23 $ 0.22 $ 0.50 $ 0.41 $ 0.21Lease operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.61 $ 0.94 $ 1.41 $ 0.49 $ 0.63Depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1.81 $ 2.15 $ 3.67 $ 1.95 $ 1.82General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1.13 $ 1.42 $ 2.50 $ 0.81 $ 1.13

(1) Estimated using a conversion ratio of one Bbl per six Mcf.

The following table sets forth information regarding our average net daily production and totalproduction for the year ended December 31, 2010 from our primary operating areas:

Average Net Daily Production Total NetProduction(MMcfe)

Percentage ofTotal Net

ProductionGas

(Mcf/d)Oil

(Bbls/d)Gas Equivalent

(Mcfe/d)

South Texas: – –Eagle Ford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 19 119 43 0.5Austin Chalk(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – – – –

Area Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 19 119 43 0.5

NW Louisiana/E Texas:Haynesville . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,127 1 17,132 6,253 72.7Cotton Valley(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,840 40 6,074 2,218 25.8

Area Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,967 41 23,206 8,471 98.5

SW Wyoming, NE Utah, SE Idaho(1) . . . . . . . . . . . . . . . . . . . . . . . . . . – – – – –SE New Mexico, West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 31 228 83 1.0

Total 23,014 91 23,553 8,597 100.0

(1) We currently have no production from our acreage in southwest Wyoming and adjacent areas of Utah and Idaho and insignificantproduction from the Austin Chalk formation in south Texas.

(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in OrangeCounty, Texas and two wells producing from the San Miguel formation in Zavala County, Texas.

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The following table sets forth information regarding our average net daily production and totalproduction for the nine months ended September 30, 2011 from our primary operating areas:

Average Net Daily Production Total NetProduction(MMcfe)

Percentage ofTotal Net

ProductionGas

(Mcf/d)Oil

(Bbls/d)Gas Equivalent

(Mcfe/d)

South Texas:Eagle Ford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,320 316 3,214 877 7.6Austin Chalk(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – – – –

Area Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,320 316 3,214 877 7.6

NW Louisiana/E Texas:Haynesville . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32,074 1 32,082 8,758 75.5Cotton Valley(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,538 70 6,958 1,900 16.4

Area Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38,612 71 39,040 10,658 91.9

SW Wyoming, NE Utah, SE Idaho(1) . . . . . . . . . . . . . . . . . . . . . . . . . . – – – – –SE New Mexico, West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 27 230 63 0.5

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40,003 414 42,484 11,598 100.0

(1) We currently have no production from our acreage in southwest Wyoming and adjacent areas of Utah and Idaho and insignificantproduction from the Austin Chalk formation in south Texas.

(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in OrangeCounty, Texas and two wells producing from the San Miguel formation in Zavala County, Texas.

Our total production of 11.6 Bcfe for the nine months ended September 30, 2011, was an increase of93% over our total production of 6.0 Bcfe for the nine months ended September 30, 2010. This increasedproduction is primarily due to drilling operations in the Haynesville shale, but also reflects initial productionfrom our first two operated wells in the Eagle Ford shale. Our total production of 8.6 Bcfe for the yearended December 31, 2010, was an increase of 72% over our total production of 5.0 Bcfe for the year endedDecember 31, 2009. Most of this increase is attributable to our drilling operations in the Haynesville shaleplay. Our 2009 total production of 5.0 Bcfe was a 51% increase over our total production of 3.3 Bcfe in2008. Most of this increase is attributable to our drilling operations in the Haynesville shale. In addition, asa result of production from new wells that were completed in 2011, our daily production for the nine monthsended September 30, 2011 averaged approximately 42.5 MMcfe per day.

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Producing Wells

The following table sets forth information relating to producing wells at September 30, 2011. Wells areclassified as oil or natural gas according to their predominant production stream. We do not have anycurrently active dual completions. We have an approximate average working interest of 92% in all wellsthat we operate. For wells where we are not the operator, our working interests range from less than 1% toas much as 44%, and average approximately 11%. In the table below, gross wells are the total number ofproducing wells in which we own a working interest, and net wells represent the total of our fractionalworking interests owned in the gross wells.

Natural Gas Wells Oil Wells Total Wells

Gross Net Gross Net Gross Net

South Texas:Eagle Ford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0 2.0 3.0 1.4 5.0 3.4Austin Chalk(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – – – – –

Area Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0 2.0 3.0 1.4 5.0 3.4NW Louisiana/E Texas:

Haynesville . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83.0 10.6 – – 83.0 10.6Cotton Valley(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106.0 69.7 2.0 2.0 108.0 71.7

Area Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 189.0 80.3 2.0 2.0 191.0 82.3SW Wyoming, NE Utah, SE Idaho(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – – – – –SE New Mexico, West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.0 0.6 12.0 5.1 13.0 5.7

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 192.0 82.9 17.0 8.5 209.0 91.4

(1) We currently have no producing wells on our acreage in southwest Wyoming and adjacent areas of Utah and Idaho and insignificantproduction from the Austin Chalk formation in south Texas.


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Estimated Proved Reserves

The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2010,2009 and 2008 and at September 30, 2011. The reserves estimates at December 31, 2008 presented in thetable below were based on evaluations prepared by our engineering staff and have been audited for theirreasonableness by LaRoche Petroleum Consultants, Ltd., independent reservoir engineers. The reservesestimates at December 31, 2010 and 2009 and at September 30, 2011 were based on evaluations preparedby our engineering staff and have been audited for their reasonableness by Netherland, Sewell &Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordancewith the SEC’s rules for oil and natural gas reserves reporting that were in effect at the time of thepreparation of the reserves report. The estimated reserves shown are for proved reserves only and do notinclude any unproved reserves classified as probable or possible reserves that might exist for our properties,nor do they include any consideration that could be attributable to interests in unproved and unevaluatedacreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gasreserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological andengineering data demonstrate with reasonable certainty to be recoverable in future years from knownreservoirs under existing economic and operating conditions. Our total estimated proved reserves areestimated using a conversion ratio of one Bbl per six Mcf.

At December 31,(1) At September 30,

2010 2009 2008 2011

Estimated Proved Reserves Data:(2)

Estimated proved reserves:Natural gas (Bcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127.4 63.9 19.2 155.3Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152 103 131 1,083

Total (Bcfe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128.3 64.5 20.0 161.8

Estimated proved developed reserves:Natural gas (Bcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43.1 25.4 19.2 52.6Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152 103 131 518

Total (Bcfe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44.1 26.0 20.0 55.8

Percent developed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34.3% 40.3% 100.0% 34.5%

Estimated proved undeveloped reserves:Natural gas (Bcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84.3 38.6 – 102.7Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – – 565

Total (Bcfe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84.3 38.6 – 106.0

PV-10(3) (in thousands) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $119,869 $70,359 $44,069 $155,217Standardized Measure(4) (in thousands) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $111,077 $65,061 $43,254 $143,372


(2) Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, withoutgiving effect to derivative transactions, and were held constant throughout the life of the properties. The index prices were $41.00 perBbl for oil and $5.710 per MMBtu for natural gas at December 31, 2008. The unweighted arithmetic averages of thefirst-day-of-the-month prices for the 12 months ended December 31, 2009 were $57.65 per Bbl for oil and $3.866 per MMBtu for naturalgas, for the 12 months ended December 31, 2010 were $75.96 per Bbl for oil and $4.376 per MMBtu for natural gas, and for the12-month period from October 2010 to September 2011 were $91.00 per Bbl for oil and $4.158 per MMBtu for natural gas. These priceswere adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factorsaffecting the price received at the wellhead.

(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAPfinancial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fairmarket value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of provedreserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specifictax characteristics of such entities. Our PV-10 at December 31, 2008, 2009, and 2010 and at September 30, 2011 may be reconciled to

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our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxesassociated with such reserves. The discounted future income taxes at December 31, 2008, 2009 and 2010 and at September 30, 2011were, in thousands, $815, $5,298, $8,792 and $11,845 respectively.


In 2009, the SEC provided new guidelines for estimating and reporting oil and natural gas reserves.Included in these new guidelines were two important changes impacting our reserves estimates and value atDecember 31, 2009. First, proved undeveloped reserves can be assigned to well locations more than oneoffset location away from an existing well if supported by geologic continuity and existing technology.Second, under these new guidelines, oil and natural gas reserves at December 31, 2010 and 2009 and atSeptember 30, 2011 were estimated using an unweighted, arithmetic average of the first-day-of-the-monthoil and natural gas prices for the periods January through December 2009, January through December 2010,and October 2010 through September 2011, respectively, as further described in footnote two to the tableabove. Prior to these periods, SEC guidelines for estimating and reporting oil and natural gas reservesrequired using commodity prices at the date of the reserves estimate, or, in the cases above, at December 31,2008, as further described in footnote two to the table above.

Our total proved oil and natural gas reserves increased from 128.3 Bcfe at December 31, 2010 to161.8 Bcfe at September 30, 2011. Most of this increase is attributable to proved reserves added due to ourdrilling operations in the Haynesville shale play. The increase in proved oil reserves specifically from152 MBbls at December 31, 2010 to 1,083 MBbls at September 30, 2011 is attributable to proved oilreserves added due to our drilling operations in the Eagle Ford shale play. Our proved reserves atSeptember 30, 2011 were made up of approximately 96% natural gas and 4% oil. Our proved developedreserves increased from 44.1 Bcfe at December 31, 2010 to 55.8 Bcfe at September 30, 2011 due primarilyto proved developed reserves added as a result of drilling operations in the Haynesville shale play. Theincrease in proved developed oil reserves specifically from 152 MBbls at December 31, 2010 to 518 MBblsat September 30, 2011 is attributable to proved developed oil reserves added due to our drilling operationsin the Eagle Ford shale play. Our proved undeveloped reserves increased from 84.3 Bcfe at December 31,2010 to 106.0 Bcfe at September 30, 2011 due primarily to our drilling operations in the Haynesville shale.The increase in our proved undeveloped oil reserves specifically from zero to 565 MBbls at September 30,2011 is attributable to our drilling operations in the Eagle Ford shale play. The net increase of 21.7 Bcfe inour proved undeveloped reserves from December 31, 2010 to September 30, 2011 is composed of (1)additions of 25.4 Bcfe to proved undeveloped reserves identified through drilling operations, less (2) theconversion of 1.4 Bcfe of proved undeveloped reserves to proved developed reserves, less (3) the downwardrevisions of proved undeveloped reserves by 2.3 Bcfe in the period. During this period, we recorded nochanges to proved undeveloped reserves as a result of the acquisition or divestment of reserves. We had noproved undeveloped reserves assigned to our properties at December 31, 2008, and hence, all of our provedundeveloped reserves have been added since that time. Thus, at September 30, 2011, we had no provedreserves in our estimates that remained undeveloped for five years or more following their initial booking.

Our total proved oil and natural gas reserves increased from 64.5 Bcfe at December 31, 2009 to128.3 Bcfe at December 31, 2010. Taking into consideration the 8.6 Bcfe in production for the year endedDecember 31, 2010, we added approximately 72.4 Bcfe in proved reserves during 2010, which represents again of about 112%. Almost all of this increase is attributable to proved reserves added due to drillingoperations in the Haynesville shale play. Our proved reserves at December 31, 2010 were made up ofapproximately 99% natural gas and 1% oil. Our proved developed reserves increased from 26.0 Bcfe atDecember 31, 2009 to 44.1 Bcfe at December 31, 2010 due primarily to proved developed reserves added

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as a result of drilling operations in the Haynesville shale play. Our proved undeveloped reserves increasedfrom 38.6 Bcfe at December 31, 2009 to 84.3 Bcfe at December 31, 2010 due to drilling operations in theHaynesville shale play.

Our total proved oil and natural gas reserves increased from 20.0 Bcfe at December 31, 2008 to64.5 Bcfe at December 31, 2009. Taking into consideration the 5.0 Bcfe in total production for 2009, weadded approximately 49.5 Bcfe in proved reserves during 2009, which represents a gain of about 248%. Theresults from the Haynesville shale drilling program in our Elm Grove/Caspiana asset in northwest Louisianaduring 2009 resulted in a significant increase in our total proved reserves at December 31, 2009. Our provedreserves at December 31, 2009 were made up of approximately 99% natural gas and 1% oil. Our proveddeveloped reserves increased from 20.0 Bcfe at December 31, 2008 to 26.0 Bcfe at December 31, 2009,which is also attributable to the Haynesville shale drilling program in our Elm Grove/Caspiana asset during2009. Our proved undeveloped reserves increased from zero at December 31, 2008 to 38.6 Bcfe atDecember 31, 2009 due entirely to proved undeveloped reserves added as a result of drilling operations inthe Haynesville shale play during 2009.

The following table sets forth additional summary information by operating area with respect to ourestimated proved reserves at September 30, 2011:

Net Proved Reserves(1)

Oil GasGas

Equivalent PV-10(2)Standardized

Measure(3)

(MBbls) (Bcf) (Bcfe) (in millions) (in millions)South Texas:

Eagle Ford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 910 3.0 8.4 37.2 34.4Austin Chalk(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – – – –

Area Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 910 3.0 8.4 37.2 34.4

NW Louisiana/E Texas:Haynesville . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 136.6 136.6 92.6 85.6Cotton Valley(5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81 15.6 16.1 23.2 21.4

Area Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81 152.2 152.7 115.8 107.0

SW Wyoming, NE Utah, SE Idaho(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – – – –SE New Mexico, West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92 0.1 0.7 2.2 2.0

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,083 155.3 161.8 155.2 143.4


(2) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAPfinancial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fairmarket value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of provedreserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specifictax characteristics of such entities. Our PV-10 at September 30, 2011 may be reconciled to our Standardized Measure of discountedfuture net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. Thediscounted future income taxes at September 30, 2011 were approximately $11.8 million.


(4) At September 30, 2011, we had no proved reserves attributable to the Austin Chalk formation in south Texas or to our acreage insouthwest Wyoming and adjacent areas of Utah and Idaho.

(5) Includes Cotton Valley and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas andtwo wells producing from the San Miguel formation in Zavala County, Texas.

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Technology Used to Establish Reserves

Under the new SEC rules, proved reserves are those quantities of oil and natural gas, which, byanalysis of geoscience and engineering data, can be estimated with reasonable certainty to be economicallyproducible from a given date forward, from known reservoirs, and under existing economic conditions,operating methods and government regulations. The term “reasonable certainty” implies a high degree ofconfidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate.Reasonable certainty can be established using techniques that have been proven effective by actualproduction from projects in the same reservoir or an analogous reservoir or by other evidence using reliabletechnology that establishes reasonable certainty. Reliable technology is a grouping of one or moretechnologies (including computational methods) that have been field tested and have been demonstrated toprovide reasonably certain results with consistency and repeatability in the formation being evaluated or inan analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, we usedtechnologies that have been demonstrated to yield results with consistency and repeatability. Thetechnologies and technical data used in the estimation of our proved reserves include, but are not limited to,electric logs, radioactivity logs, core analyses, geologic maps and available downhole and production data,seismic data and well test data. Reserves for proved developed producing wells were estimated usingproduction performance and material balance methods. Certain new producing properties with littleproduction history were forecast using a combination of production performance and analogy to offsetproduction. Non-producing reserves estimates for both developed and undeveloped properties were forecastusing either volumetric and/or analogy methods.

Internal Control Over Reserves Estimation Process

We maintain an internal staff of petroleum engineers and geoscience professionals to ensure theintegrity, accuracy and timeliness of the data used in our reserves estimation process. Our ReservesManager is primarily responsible for overseeing the preparation of our reserves estimates and has over15 years of industry experience. Our Reserves Manager received his Ph.D. degree in Petroleum Engineeringfrom Texas A&M University, is a Licensed Professional Engineer in the State of Texas and received acertificate of completion in a prescribed course of study in Reserves and Evaluation from Texas A&MUniversity in May 2009. Our Reserves Manager reports directly to our Vice President – ReservoirEngineering. Our Vice President – Reservoir Engineering is responsible for reviewing and approving ourreserves estimates and has over 30 years of industry experience. Following the preparation of our reservesestimates, for the years ended December 31, 2010 and 2009 and for the nine month period endedSeptember 30, 2011, we had our reserves estimates audited for their reasonableness by Netherland,Sewell & Associates, Inc., our independent petroleum engineers. Following the preparation of our reservesestimates, for the year ended December 31, 2008, we had our reserves estimates audited for theirreasonableness by LaRoche Petroleum Consultants, Ltd., our independent petroleum engineers at that time.The Engineering Committee of our board of directors reviews the reserves report and our reservesestimation process, and the results of the reserves report and the independent audit of our reserves arereviewed by members of our board of directors, including members of our Audit Committee.

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Acreage Summary

The following table sets forth the approximate acreage in which we held a leasehold, mineral or otherinterest at September 30, 2011. At that date, only about 11% of our total acreage had been developed,although these percentages are much higher in northwest Louisiana and east Texas.

Developed Acres Undeveloped Acres Total Acres


South Texas:Eagle Ford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,696 1,422 50,357 27,484 52,053 28,906Austin Chalk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – 24,454 14,849 24,454 14,849

Area Total(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,696 1,422 50,357 27,484 52,053 28,906

NW Louisiana/E Texas:Haynesville . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,760 10,645 4,337 4,060 23,097 14,705Cotton Valley(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21,039 17,901 5,502 5,335 26,541 23,236

Area Total(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23,080 19,696 6,048 5,781 29,128 25,477

SW Wyoming, NE Utah, SE Idaho . . . . . . . . . . . . . . . . . . . . . . . . . . – – 144,368 135,862 144,368 135,862SE New Mexico, West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,160 1,038 9,554 6,481 10,714 7,519

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,936 22,156 210,327 175,608 236,263 197,764

(1) Some of the same leases cover the net acres shown for the Eagle Ford shale and the Austin Chalk formation, a shallower formation thanthe Eagle Ford shale. Consequently, the total acreage will not equal the sum of the acreage by operating area.

(2) Includes shallower zones and also includes acreage surrounding one well producing from the Frio formation in Orange County, Texas.

(3) Some of the same leases cover the net acres shown for the Haynesville formation and the Cotton Valley formation, a shallower formationthan the Haynesville shale. Consequently, the total acreage will not equal the sum of the acreage by operating area.

Undeveloped Acreage Expiration

The following table sets forth the number of gross and net undeveloped acres at September 30, 2011that will expire prior to December 31, 2013 by operating area unless production is established within thespacing units covering the acreage prior to the expiration dates or unless the existing leases are renewedprior to expiration:

AcresExpiring

2011Acres

Expiring 2012Acres

Expiring 2013


South Texas:Eagle Ford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,341 279 15,815 4,353 14,345 9,092Austin Chalk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 597 120 6,051 1,122 3,848 2,644

Area Total(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,341 279 15,815 4,353 14,345 9,092

NW Louisiana/E Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Haynesville . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173 125 815 487 118 118Cotton Valley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 186 138 921 493 118 118

Area Total(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 186 138 921 493 118 118

SW Wyoming, NE Utah, SE Idaho . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – 102,678 93,356 8,461 8,301SE New Mexico, West Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,362 2,723 1,725 92 8,454 2,715

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,889 3,140 121,139 98,294 31,378 20,226

(1) Some of the same leases cover the net acres shown for the Eagle Ford shale and the Austin Chalk formation, a shallower formation than theEagle Ford shale. Consequently, the total acreage will not equal the sum of the acreage by operating area.

(2) Some of the same leases cover the net acres shown for the Haynesville shale and the Cotton Valley formation, a shallower formation than theHaynesville shale. Consequently, the total acreage will not equal the sum of the acreage by operating area.

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Many of the leases comprising the acreage set forth in the table above will expire at the end of theirrespective primary terms unless production from the acreage has been established prior to such date, inwhich event the lease will remain in effect until the cessation of production in commercial quantities. Wealso have options to extend some of our leases through payment of additional lease bonus payments prior tothe expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon theexpiration of certain of our acreage; however, there may be third party leases that become effectiveimmediately if our leases expire at the end of their respective terms and production has not been establishedprior to such date. Our leases are mainly fee leases with three to five years of primary term. We believe thatour lease terms are similar to our competitors’ fee lease terms as they relate to both primary term androyalty interests.

Drilling Results

The following table summarizes our drilling activity for the three years ended December 31, 2010,2009 and 2008 and the nine months ended September 30, 2011:


Nine MonthsEnded

September 30,

2010 2009 2008 2011

Gross Net Gross Net Gross Net Gross Net

Development WellsProductive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 1.7 3 1.3 25 12.7 18 0.4Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – – – – – – –

Exploration WellsProductive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 3.4 15 6.0 12 8.6 15 5.5Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – 2 2.0 1 1.0 – –

Total WellsProductive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 5.1 18 7.3 37 21.3 33 5.9Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – 2 2.0 1 1.0 – –

Marketing

Our crude oil is generally sold under short-term, extendable and cancellable agreements withunaffiliated purchasers based on published price bulletins reflecting an established field posting price. As aconsequence, the prices we receive for crude oil and liquids move up and down in direct correlation with theoil market as it reacts to supply and demand factors. Transportation costs related to moving crude oil arealso deducted from the price received for crude oil.

Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Naturalgas produced by us is sold at various delivery points at or near producing wells to both unaffiliatedindependent marketing companies and unaffiliated mid-stream companies. We receive proceeds from pricesthat are based on various pipeline indices less any associated fees. When there is an opportunity to do so,the mid-stream companies may, at our request, process our natural gas at a processing facility and extractliquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on a negotiatedpercentage of the proceeds that are generated from the mid-stream company’s sale of the liquids, or basedon other negotiated pricing arrangements.

The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause pricefluctuation include the level of demand for oil and natural gas, weather conditions, hurricanes in the Gulf

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Coast region, natural gas storage levels, domestic and foreign governmental regulations, the actions ofOPEC, price and availability of alternative fuels, political conditions in oil and natural gas producingregions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overalleconomic conditions. Decreases in these commodity prices do adversely affect the carrying value of ourproved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and naturalgas production do occur from time to time due to downstream pipeline system failure, capacity issues andscheduled maintenance, as well as maintenance and repairs involving our own well operations. Thesesituations do curtail our production capabilities and ability to maintain a steady source of revenue for ourcompany. In addition, demand for natural gas has historically been seasonal in nature, with peak demandand typically higher prices during the colder winter months. See “Risk Factors — Our success is dependenton the prices of oil and natural gas. Low oil or natural gas prices and the substantial volatility in these pricesmay adversely affect our financial condition and our ability to meet our capital expenditure requirementsand financial obligations.”

For the year ended December 31, 2008, we had two significant purchasers that each accounted formore than 10% of our total oil and natural gas revenues: Regency Gas Services LP (45%) and J-WOperating Company (24%). For the year ended December 31, 2009, we had three significant purchasers thateach accounted for more than 10% of our total oil and natural gas revenues: Chesapeake Operating Inc.(32%), Regency Gas Services LP (25%), and J-W Operating Company (17%). For the year endedDecember 31, 2010, we had three significant purchasers that each accounted for more than 10% of our totaloil and natural gas revenues: Chesapeake Operating Inc. (42%), Regency Gas Services LP (17%) andPetrohawk Energy Corporation (11%). Due to the nature of the markets for oil and natural gas, we do notbelieve that the loss of any one of these purchasers would have a material adverse impact on our financialcondition, results of operations or cash flows for any significant period of time.

While we do not have any commitments to sell a fixed and determinable quantity of oil or natural gasto a particular buyer, we are party to two natural gas transportation agreements at December 31, 2010 andSeptember 30, 2011 that require us to deliver a specified volume of natural gas through pipelines for a fixedperiod of time. If we fail to meet the volume requirements, we are required to pay an amount to the ownersof the pipelines to offset a portion of the expenses they incurred in building the pipelines to our welllocations. Neither of these contracts constitutes a material commitment.

Title to Properties

We endeavor to assure that title to our properties is in accordance with standards generally accepted inthe oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, termassignments and other contractual arrangements with third parties, the terms of which often will require thedrilling of wells or the undertaking of other exploratory or development activities in order to retain ourinterests in the acreage. Our title to these contractual interests will be contingent upon our satisfactoryfulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incidentto financing arrangements, operating agreements, taxes and other burdens that we believe will not materiallyinterfere with the use and operation of or affect the value of these properties. We intend to maintain ourleasehold interests by making lease rental payments or by producing wells in paying quantities prior toexpiration of various time periods to avoid lease termination. Certain of the leases that we have obtained todate have been purchased by and in the name of professional lease brokers as our nominee. See “RiskFactors — We may incur losses or costs as a result of title deficiencies in the properties in which weinvest.”

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Competition

The oil and natural gas industry is highly competitive. We compete and will continue to compete withmajor and independent oil and natural gas companies for exploration opportunities, acreage and propertyacquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill,operate and develop our properties. Most of our competitors have substantially greater financial resources,staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of anychanges in federal, state and local laws and regulations more easily than we can, which would adverselyaffect our competitive position. These competitors may be able to pay more for drilling rigs or exploratoryprospects and productive oil and natural gas properties and may be able to define, evaluate, bid for andpurchase a greater number of properties and prospects than we can. Our competitors may also be able toafford to purchase and operate their own drilling rigs.

Our ability to drill and explore for oil and natural gas and to acquire properties will depend upon ourability to conduct operations, to evaluate and select suitable properties and to consummate transactions inthis highly competitive environment. We have been conducting field operations since 2004 while ourcompetitors have a longer history of operations, and most of them have also demonstrated the ability tooperate through industry cycles.

The oil and natural gas industry also competes with other energy-related industries in supplying theenergy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors –Competition in the oil and natural gas industry is intense, making it more difficult for us to acquireproperties, market natural gas and secure trained personnel.”

Regulation

Oil and Natural Gas Regulation

Our oil and natural gas exploration, development, production and related operations are subject toextensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules andregulations can result in substantial penalties. The regulatory burden on the oil and natural gas industryincreases our cost of doing business and affects our profitability. Because these rules and regulations arefrequently amended or reinterpreted and new rules and regulations are promulgated, we are unable topredict the future cost or impact of complying with the laws, rules and regulations to which we are, or willbecome, subject. Our competitors in the oil and natural gas industry are generally subject to the sameregulatory requirements and restrictions that affect our operations. We cannot predict the impact of futuregovernment regulation on our properties or operations.

Texas, New Mexico, Louisiana, Wyoming, Idaho and Utah and many other states require permits fordrilling operations, drilling bonds and reports concerning operations and impose other requirements relatingto the exploration, development and production of oil and natural gas. Many states also have statutes orregulations addressing conservation of oil and natural gas matters, including provisions for the unitization orpooling of oil and natural gas properties, the establishment of maximum rates of production from wells, theregulation of well spacing, the surface use and restoration of properties upon which wells are drilled, thesourcing and disposal of water used in the drilling and completion process and the plugging andabandonment of these wells. Many states restrict production to the market demand for oil and natural gas.Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries.Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations onproduction by restricting the rate of flow of oil and natural gas wells below natural production capacity in

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order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production orseverance tax with respect to the production and sale of oil, natural gas and natural gas liquids within itsjurisdiction.

Some of our oil and natural gas leases are issued by agencies of the federal government, as well asagencies of the states in which we operate. These leases contain various restrictions on access anddevelopment and other requirements that may impede our ability to conduct operations on the acreagerepresented by these leases.

Our sales of natural gas, as well as the revenues we receive from our sales, are affected by theavailability, terms and costs of transportation. The rates, terms and conditions applicable to the interstatetransportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, orFERC, under the Natural Gas Act, as well as under Section 311 of the Natural Gas Policy Act. Since 1985,FERC has implemented regulations intended to increase competition within the natural gas industry bymaking natural gas transportation more accessible to natural gas buyers and sellers on an open-access,non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated and wecan give no assurance that the current less stringent regulatory approach of FERC will continue.

In 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things,amended the Natural Gas Act to prohibit market manipulation by any entity, to direct FERC to facilitatemarket transparency in the market for sale or transportation of physical natural gas in interstate commerce,and to significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Actof 1978, or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implementthe Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, inaddition to FERC-imposed penalties, we may also be subject to third party damage claims.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis forintrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny givento intrastate natural gas pipeline rates and services varies from state to state. Because these regulations willapply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that theregulation in any states in which we operate will not affect our operations in any way that is materiallydifferent from our competitors that are similarly situated.

The price we receive from the sale of oil and natural gas liquids will be affected by the availability,terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oilpipelines can change rates based on an inflation index, though other rate mechanisms may be used inspecific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by stateregulatory commissions, which varies from state to state. We are not able to predict with certainty theeffects, if any, of these regulations on our operations.

In 2007, the Energy Independence & Security Act of 2007, or EISA, went into effect. The EISA,among other things, prohibits market manipulation by any person in connection with the purchase or sale ofcrude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations thatthe Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce theregulations and establishes penalties for violations thereunder. We cannot predict any future regulations ortheir impact.

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U.S. Federal and State Taxation

The federal, state and local governments in the areas in which we operate impose taxes on the oil andnatural gas products we sell and, for many of our wells, sales and use taxes on significant portions of ourdrilling and operating costs. In the past, there has been a significant amount of discussion by legislators andpresidential administrations concerning a variety of energy tax proposals. President Obama has recentlyproposed sweeping changes in federal laws on the income taxation of small oil and natural gas explorationand production companies such as us. President Obama has proposed to eliminate allowing small U.S. oiland natural gas companies to deduct intangible U.S. drilling costs as incurred and percentage depletion.Many states have raised state taxes on energy sources, and additional increases may occur. Changes to taxlaws could adversely affect our business and our financial results.

Hydraulic Fracturing Policies and Procedures

We use hydraulic fracturing as a means to maximize the productivity of our oil and natural gas wells inalmost every well that we drill and complete. Our engineers responsible for these operations attendspecialized hydraulic fracturing training programs taught by industry professionals. Although averagedrilling and completion costs for each area will vary, as will the cost of each well within a given area, onaverage approximately 50% of the drilling and completion costs for our horizontal wells are associated withhydraulic fracturing activities. These costs are treated in the same way that all other costs of drilling andcompletion of our wells are treated and are built into and funded through our normal capital expendituresbudget.

The protection of groundwater quality is important to us. We believe that we follow all state andfederal regulations and apply industry standard practices for groundwater protection in our operations.These measures are subject to close supervision by state and federal regulators (including the BLM withrespect to federal acreage). Our policy and practice is to follow all applicable guidelines and regulations inthe areas where we conduct hydraulic fracturing. A surface casing string is set deeper than the deepestusable quality fresh water zones and cemented back to the surface in accordance with the appropriateregulations, lease requirements and legal requirements. This surface string of casing is then pressure testedto ensure mechanical integrity of the casing string prior to continuing drilling operations. We follow strictquality control procedures for conducting hydraulic fracturing operations that include a multi-point safetychecklist, managing inventories of all materials and chemicals on the well site and ensuring that MaterialSafety Data Sheets are on location for every well that is hydraulically fractured. We contract with thirdparties to conduct hydraulic fracturing operations, and we send at least one of our own engineers to the wellsite to personally supervise each hydraulic fracture treatment. On a real-time basis, we closely monitorpump rates and pressures on existing casing strings to ensure that wellbore integrity is maintained duringhydraulic fracturing operations. Our policy regarding monitoring well pressures would require stopping thehydraulic fracturing operations upon any indication that wellbore integrity may have been compromised.

We follow additional regulatory requirements and recommended practices to ensure wellbore integrity andfull isolation of any underground aquifers and protection of surface waters. These include the following:

• Prior to perforating the production casing and hydraulic fracturing operations, a cement bond log isrun to verify cement integrity between the formation to be fractured and shallow formations. Then,the casing is pressure tested to ensure no leaks exist within the casing;

• Before the fracturing operation commences, all surface equipment is pressure tested, which includesthe wellhead and all high pressure lines and connections leading from the pumping equipment to the

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wellhead. During the pumping phases of the hydraulic fracturing treatment, the service companies weengage must provide specialized equipment to monitor and record surface pressures, pumping rates,volumes and chemical concentrations to ensure the treatment is proceeding as designed and thewellbore integrity is sound. Our engineers at the job site have laptop computers with special softwareto monitor and collect, for permanent archiving, information from the hydraulic fracturing operations.As part of this process, when fracturing operations are being performed down casing, we also monitorthe casing annular pressure to ensure that there is no communication of hydraulic pressure andfracture fluids outside the casing that could communicate with shallow formations. Should anyproblem be detected at any time during the hydraulic fracturing treatment, the operation would beshut down until the problem is evaluated, reported and remediated; and

• As a means to further protect against the negative impacts of any potential surface release of fluidsassociated with the hydraulic fracturing operation, special precautions are taken both during and afterthe operation. During the fracturing operation, all chemicals are mixed into the fracturing fluid as it isbeing pumped into the well as opposed to being pre-mixed in the “frac pits” or work tanks. Whilechemical additives are stored on location in independent containment vessels, only fresh water isstored in the frac pits or work tanks. All pumping equipment used during the operation is pressuretested and monitored. When the well is flowed back, after the fracturing operation, all fluids areproduced into closed-top storage tanks. All flowback equipment and piping are pressure tested toensure no leaks are present and the fluids are properly contained.

Once the final string of casing is set in place, cement is pumped into the casing/wellbore annuluswhere it hardens and creates a permanent, isolating barrier between the steel casing pipe and surroundinggeological formations. This aspect of the well design establishes a pressure seal essentially eliminating anypathway for the fracturing fluid to contact fresh water aquifers during the hydraulic fracturing operation.Furthermore, in the areas in which we conduct hydraulic fracturing, the hydrocarbon bearing formations areseparated from any usable quality underground fresh water aquifers by thousands of feet of impermeablerock layers. This natural geological separation serves as a protective barrier, preventing migration offracturing fluids or hydrocarbons upwards into any fresh water zones.

Although rare, if and when the cement and steel casing used in well construction need to beremediated, we deal with these problems by evaluating the issue, running diagnostic tools including cementbond logs, temperature logs and pressure testing, followed by pumping remedial cement jobs. We repairwellhead leaks by replacing wellhead components, re-installing components to proper specifications and re-testing. In wellbores that utilize downhole packers, pressure integrity issues are rectified by repairing orreplacing packers. Casing integrity lost due to corrosion on a producing well is remedied by identifying thespecific location of the leak by cased hole logging tools, mechanical isolation and pressure testing or otherdiagnostic methods, followed by high pressure squeeze cementing and subsequent pressure testing to ensurethe leak has been repaired. Throughout the process we believe we abide by applicable regulations.

The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds ofman-made propping agents. We use major hydraulic fracturing service companies who track and reportchemical additives that are used in the fracturing operation as required by the appropriate governmentalagencies. These service companies fracture stimulate thousands of wells each year for the industry andinvest millions of dollars to protect the environment through rigorous safety procedures, and also work todevelop more environmentally friendly fracturing fluids. As previously mentioned we also follow strictsafety procedures and monitor all aspects of the fracturing operation to ensure environmental protection.We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures.

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While current fracture stimulation procedures utilize a significant amount of water, we typicallyrecover less than 10% of this fracture stimulation water before produced saltwater becomes a significantportion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in away that does not impact surface waters. All produced water is disposed of in permitted and regulateddisposal facilities.

Environmental Regulation

The exploration, development and production of oil and natural gas, including the operation ofsaltwater injection and disposal wells, are subject to various federal, state and local environmental laws andregulations. These laws and regulations can increase the costs of planning, designing, installing andoperating oil and natural gas wells. Our activities are subject to a variety of environmental laws andregulations, including but not limited to: the Oil Pollution Act of 1990, or OPA 90, the Clean Water Act, orCWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, theResource Conservation and Recovery Act, or RCRA, the Clean Air Act, or CAA, the Safe Drinking WaterAct, or SDWA and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutesand regulations. We are also subject to regulations governing the handling, transportation, storage anddisposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, thatmay result from our oil and natural gas operations. Civil and criminal fines and penalties may be imposedfor noncompliance with these environmental laws and regulations. Additionally, these laws and regulationsrequire the acquisition of permits or other governmental authorizations before undertaking some activities,limit or prohibit other activities because of protected wetlands, areas or species and require investigationand cleanup of pollution. We expect to remain in compliance in all material respects with currentlyapplicable environmental laws and regulations and expect that these laws and regulations will not have amaterial adverse impact on us.

The OPA 90 and its regulations impose requirements on “responsible parties” related to the preventionof crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoiningshorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict,joint and several financial liability for removal costs and other damages, including natural resourcedamages, caused by an oil spill that is covered by the statute. It also imposes other requirements onresponsible parties, such as the preparation of an oil spill contingency plan. Failure to comply with theOPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operationson acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliancewith applicable requirements under the OPA 90 will not have a material and adverse effect on us.

The CWA imposes restrictions and strict controls regarding the discharge of produced waters and otherwastes into navigable waters. These controls have become more stringent over the years, and it is possiblethat additional restrictions will be imposed in the future. Permits are required to discharge pollutants intostate and federal waters and to conduct construction activities in waters and wetlands. Certain stateregulations and the general permits issued under the federal National Pollutant Discharge EliminationSystem program prohibit the discharge of produced water, produced sand, drilling fluids, drill cuttings andcertain other substances related to the oil and natural gas industry into certain coastal and offshore waters.Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and productionfacilities to obtain permits for storm water discharges. Costs may be associated with the treatment ofwastewater or developing and implementing storm water pollution prevention plans. The CWA and

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comparable state statutes provide for civil, criminal and administrative penalties for any unauthorizeddischarges of oil and other pollutants and impose liability for the costs of removal or remediation ofcontamination resulting from such discharges. In furtherance of the CWA, the EPA promulgated the SpillPrevention, Control, and Countermeasure, or SPCC, regulations, which require certain oil-storing facilitiesto prepare plans and meet construction and operating standards.

CERCLA, also known as the “Superfund” law, and comparable state statutes impose liability, withoutregard to fault or the legality of the original conduct, on various classes of persons that are considered tohave contributed to the release of a “hazardous substance” into the environment. These persons include theowner or operator of the disposal site where the release occurred and companies that disposed of, orarranged for the disposal of, the hazardous substances found at the site. Persons who are responsible forreleases of hazardous substances under CERCLA may be subject to joint and several liability for the costsof cleaning up the hazardous substances and for damages to natural resources. In addition, it is notuncommon for neighboring landowners and other third parties to file claims for personal injury and propertydamage allegedly caused by hazardous substances released into the environment. Our operations may, andin all likelihood will, involve the use or handling of materials that may be classified as hazardous substancesunder CERCLA. Furthermore, we may acquire or operate properties that unknown to us have beensubjected to, or have caused or contributed to, prior releases of hazardous wastes.

RCRA and comparable state and local statutes govern the management, including treatment, storageand disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardoussolid waste in connection with our routine operations. At present, RCRA includes a statutory exemption thatallows many wastes associated with crude oil and natural gas exploration and production to be classified asnonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Atvarious times in the past, proposals have been made to amend RCRA to eliminate the exemption applicableto crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemptionby administrative, legislative or judicial process, or through changes in applicable state statutes, wouldincrease the volume of hazardous waste we are required to manage and dispose of and would cause us, aswell as our competitors, to incur increased operating expenses. Hazardous wastes are subject to morestringent and costly disposal requirements than are nonhazardous wastes.

The CAA, as amended, and comparable state laws restrict the emission of air pollutants from manysources, including oil and natural gas production. These laws and any implementing regulations imposestringent air permit requirements and require us to obtain pre-approval for the construction or modificationof certain projects or facilities expected to produce air emissions, or to use specific equipment ortechnologies to control emissions. On July 28, 2011, the EPA proposed new regulations targeting airemissions from the oil and natural gas industry. The proposed rules, if adopted, would impose newrequirements on production and processing and transmission and storage facilities. While we may berequired to incur certain capital expenditures in the next few years for air pollution control equipment inconnection with maintaining or obtaining operating permits addressing other air emission-related issues, wedo not believe that such requirements will affect our operations in any way that is materially different fromour competitors.

Changes in environmental laws and regulations occur frequently, and any changes that result in morestringent and costly waste handling, storage, transport, disposal or cleanup requirements or operatingrequirements could materially adversely affect our operations and financial position, as well as those of theoil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions

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of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane,may be contributing to the warming of the Earth’s atmosphere. As a result, there have been attempts to passcomprehensive greenhouse gas legislation. To date, such legislation has not been enacted. Any futurefederal laws or implementing regulations that may be adopted to address greenhouse gas emissions could,and in all likelihood would, require us to incur increased operating costs adversely affecting our profits andcould adversely affect demand for the oil and natural gas we produce depressing the prices we receive foroil and natural gas.

On December 15, 2009, the EPA published its finding that emissions of greenhouse gases presented anendangerment to human health and the environment. These findings by the EPA allow the agency toproceed with the adoption and implementation of regulations that would restrict emissions of greenhousegases under existing provisions of the CAA. Subsequently, the EPA proposed and adopted two sets ofregulations, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and theother of which regulated emissions of greenhouse gases from certain large stationary sources. In addition,on October 30, 2009, the EPA published a rule requiring the reporting of greenhouse gas emissions fromspecified sources in the U.S. beginning in 2011 for emissions occurring in 2010. On November 30, 2010,the EPA released a rule that expands its final rule on greenhouse gas emissions reporting to include ownersand operators of onshore and offshore oil and natural gas production, onshore natural gas processing,natural gas storage, natural gas transmission and natural gas distribution facilities. Reporting of greenhousegas emissions from such onshore production will be required on an annual basis beginning in 2012 foremissions occurring in 2011. The adoption and implementation of any regulations imposing reportingobligations on, or limiting emissions of greenhouse gases from, our equipment and operations could, and inall likelihood will, require us to incur costs to reduce emissions of greenhouse gases associated with ouroperations adversely affecting our profits or could adversely affect demand for the oil and natural gas weproduce depressing the prices we receive for oil and natural gas.

Some states have begun taking actions to control and/or reduce emissions of greenhouse gases,primarily through the planned development of greenhouse gas emission inventories and/or regionalgreenhouse gas cap and trade programs. Although most of the state-level initiatives have to date focused onsignificant sources of greenhouse gas emissions, such as coal-fired electric plants, it is possible that lesssignificant sources of emissions could become subject to greenhouse gas emission limitations or emissionsallowance purchase requirements in the future. Any one of these climate change regulatory and legislativeinitiatives could have a material adverse effect on our business, financial condition, results of operations andcash flows.

Underground injection is the subsurface placement of fluid through a well, such as the reinjection ofbrine produced and separated from oil and natural gas production. In our industry, underground injectionnot only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it canincrease the oil production from such zone. The SDWA establishes a regulatory framework for undergroundinjection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus andto prevent migration of fluids from the injection zone into underground sources of drinking water. Thedisposal of hazardous waste by underground injection is subject to stricter requirements than the disposal ofproduced water. We currently own and operate five underground injection wells and expect to own othersimilar wells. Failure to obtain, or abide by, the requirements for the issuance of necessary permits couldsubject us to civil and/or criminal enforcement actions and penalties.

Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturingoperations, see “Business — Regulation — Hydraulic fracturing policies and procedures.” Recently, there

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has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulationas underground injection on the federal level pursuant to the SDWA. However, the U.S. Senate and Houseof Representatives have considered legislation to repeal this exemption. If enacted, these proposals wouldamend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities.If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financialassurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting andrecordkeeping obligations, and meet plugging and abandonment requirements. These legislative proposalshave also contained language to require the reporting and public disclosure of chemicals used in thefracturing process. If the exemption for hydraulic fracturing is removed from the SDWA, or if otherlegislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturingcontained in any such legislation could have a significant impact on our financial condition, results ofoperations and cash flows.

In addition, at the federal level and in some states, there has been a push to place additional regulatoryburdens upon hydraulic fracturing activities. Certain bills have been introduced in the Senate and the Houseof Representatives that, if adopted, could increase the possibility of litigation and establish an additionallevel of regulation at the federal level that could lead to operational delays or increased operating costs andcould, and in all likelihood would, result in additional regulatory burdens, making it more difficult toperform hydraulic fracturing operations and increasing our costs of compliance. At the state level, Wyomingand Texas, for example, have enacted requirements for the disclosure of the composition of the fluids usedin hydraulic fracturing. On June 17, 2011, Texas signed into law a mandate for public disclosure of thechemicals that operators use during hydraulic fracturing in Texas. The law went into effect September 1,2011. State regulators have until 2013 to complete implementing rules. In addition, at least three localgovernments in Texas have imposed temporary moratoria on drilling permits within city limits so that localordinances may be reviewed to assess their adequacy to address hydraulic fracturing activities. Additionalburdens upon hydraulic fracturing, such as reporting requirements or permitting requirements for thehydraulic fracturing activity, will result in additional expense and delay in our operations.

Oil and natural gas exploration and production, operations and other activities have been conducted atsome of our properties by previous owners and operators. Materials from these operations remain on someof the properties, and, in some instances, require remediation. In addition, we occasionally must agree toindemnify sellers of producing properties from whom we acquire reserves against some of the liability forenvironmental claims associated with these properties. While we do not believe that costs we incur forcompliance with environmental regulations and remediating previously or currently owned or operatedproperties will be material, we cannot provide any assurances that these costs will not result in materialexpenditures that adversely affect our profitability.

Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks,including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling andenvironmental compliance. It is also possible that our oil and natural gas operations may require us tomanage NORM. NORM is present in varying concentrations in sub-surface formations, includinghydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes incontact with crude oil and natural gas production and processing streams. Some states, including Texas,have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, wewill be able to control directly the operations of only those wells for which we act as the operator. Despiteour lack of control over wells owned by us but operated by others, the failure of the operator to comply withthe applicable environmental regulations may, in certain circumstances, be attributable to us.

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We are subject to the requirements of OSHA and comparable state statutes. The OSHA HazardCommunication Standard, the “community right-to-know” regulations under Title III of the federalSuperfund Amendments and Reauthorization Act and similar state statutes require us to organizeinformation about hazardous materials used, released or produced in our operations. Certain of thisinformation must be provided to employees, state and local governmental authorities and local citizens. Weare also subject to the requirements and reporting set forth in OSHA workplace standards.

We have not in the past been, and do not anticipate in the near future to be, required to expend amountsthat are material in relation to our total capital expenditures as a result of environmental laws andregulations, but since these laws and regulations are periodically amended, we are unable to predict theultimate cost of compliance. We cannot assure you that more stringent laws and regulations protecting theenvironment will not be adopted or that we will not otherwise incur material expenses in connection withenvironmental laws and regulations in the future. See “Risk Factors.”

The clear trend in environmental regulation is to place more restrictions and limitations on activitiesthat may affect the environment, and thus, any changes in environmental laws and regulations orre-interpretation of enforcement policies that result in more stringent and costly waste handling, storage,transport, disposal or remediation requirements could have a material adverse effect on our operations andfinancial position. We may be unable to pass on such increased compliance costs to our customers.Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure youthat we will not incur significant costs and liabilities as a result of such releases or spills, including any thirdparty claims for damage to property, natural resources or persons.

We maintain insurance against some, but not all, potential risks and losses associated with our industryand operations. We do not currently carry business interruption insurance. For some risks, we may notobtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Inaddition, pollution and environmental risks generally are not fully insurable. If a significant accident orother event occurs and is not fully covered by insurance, it could materially adversely affect our financialcondition, results of operations and cash flows.

Office Lease

Our corporate headquarters are located in 28,743 square feet of office space in One Lincoln Centre,5400 LBJ Freeway, Suite 1500, Dallas, Texas. In April 2011, we entered into a third amended and restatedoffice lease agreement pursuant to which our office space was increased form 20,849 to 28,743 square feetand the term of our lease was extended from July 1, 2011 to June 30, 2022. Beginning July 1, 2011, throughJune 30, 2012, we are not required to pay a monthly base rent. From July 1, 2012 through June 30, 2015,our monthly base rent is $47,905. From July 1, 2015 through June 30, 2017, our monthly base rent is$50,300. From July 1, 2017 through June 30, 2019, our monthly base rent is $52,696. From July 1, 2019through June 30, 2020, our monthly base rent is $55,091. From July 1, 2020 through the expiration date ofthe lease, our monthly base rent is $57,726. In addition, the lease contains a renewal option in our favor foran additional 60-month period at the then existing market rate as determined in accordance with the lease.

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Employees

At December 31, 2011, we had 41 full-time employees. We believe that our relationships with ouremployees are satisfactory. No employee is covered by a collective bargaining agreement. From time totime, we use the services of independent consultants and contractors to perform various professionalservices, particularly in the areas of geology and geophysics, construction, design, well site surveillance andsupervision, permitting and environmental assessment and legal and income tax preparation and accountingservices. Independent contractors, at our request, drill all of our wells and usually perform field and on-siteproduction operation services for us, including pumping, maintenance, dispatching, inspection and testing.If significant opportunities for company growth arise and require additional management and professionalexpertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary todevelop those opportunities.

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operationsin the normal course of business, we are not currently a party to any material legal proceeding. In addition,we are not aware of any material legal or governmental proceedings against us, or contemplated to bebrought against us.

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MANAGEMENT

Officers

The following table sets forth the names, ages and positions of our executive officers at January 1,2012:

Name Age Positions Held With Us

Joseph Wm. Foran 59 Chairman of the Board, Chief Executive Officer and PresidentDavid E. Lancaster 55 Executive Vice President, Chief Operating Officer and Chief Financial OfficerMatthew V. Hairford 50 Executive Vice President — OperationsDavid F. Nicklin 62 Executive Director of ExplorationWade I. Massad 44 Executive Vice President — Capital MarketsScott E. King 53 Co-Founder, Vice President — Geophysics and New VenturesBradley M. Robinson 57 Vice President — Reservoir Engineering

The following biographies describe the business experience of our executive officers. Each officerserves at the discretion of our board of directors. There are no family relationships among any of ourofficers.

Mr. Joseph Wm. Foran. Mr. Foran founded Matador Resources Company in July 2003 and has servedas Chairman of the Board, Chief Executive Officer, President and Secretary since July 2003. He is alsochairman of the board’s Executive Committee. Mr. Foran began his career as an oil and natural gasindependent in 1983 when he and his wife, Nancy, founded Foran Oil Company with $270,000 incontributed capital from 17 of his closest friends and neighbors. Foran Oil Company was later contributedinto Matador Petroleum Corporation upon its formation by Mr. Foran in 1988, and Mr. Foran served asChairman and Chief Executive Officer of that company from inception until the time of its sale to TomBrown, Inc. in June 2003 for an enterprise value of $388 million in an all-cash transaction. UnderMr. Foran’s guidance, Matador Petroleum realized a 21% average annual rate of return for its shareholdersfor 15 years. Mr. Foran is originally from Amarillo, Texas, where his family owned a pipeline constructionbusiness. From 1980 to 1983, he was Vice President and General Counsel of J. Cleo Thompson and JamesCleo Thompson, Jr., Oil Producers. Prior to that time, he was a briefing attorney to Chief Justice Joe R.Greenhill of the Supreme Court of Texas. Mr. Foran graduated with a Bachelor of Science degree inAccounting from the University of Kentucky with highest honors and a law degree from the SouthernMethodist University School of Law, where he was a Hatton W. Sumners scholar and the Leading ArticlesEditor of the Southwestern Law Review. He is currently active as a member of various industry and civicorganizations, including his church and various youth activities. In 2002, Mr. Foran was honored as theErnst & Young “Entrepreneur of the Year” for the Southwest Region. As the founder and Chairman of theBoard, Chief Executive Officer and President of Matador Resources Company, Mr. Foran has providedleadership, experience and long relationships with a vast majority of the shareholders.

Mr. David E. Lancaster. Mr. Lancaster joined Matador Resources Company in December 2003 andserves as Executive Vice President, Chief Operating Officer and Chief Financial Officer. Mr. Lancaster hasserved in several capacities since joining Matador, including Vice President – Business Development,Acquisitions and Finance from December 2003 to May 2005; Vice President and Chief Financial Officerfrom May 2005 to May 2007; and Executive Vice President and Chief Financial Officer from May 2007 toMay 2009. He assumed his current role in May 2009. From August 2000 to December 2003, he wasMarketing Manager for Schlumberger Limited’s Data & Consulting Services which provides full-fieldreservoir characterization, production enhancement, multidisciplinary reservoir and production solutionsand field development planning. In this position, he was responsible for global marketing strategies,business models, input to research and development, commercialization of new products and services and

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marketing communications. From 1999 to 2000, Mr. Lancaster was Business Manager, North and SouthAmerica, for Schlumberger Holditch-Reservoir Technologies, the petroleum engineering consultingorganization formed following Schlumberger’s acquisitions of S. A. Holditch & Associates, Inc. and InteraPetroleum Services. In this role, he was responsible for the business operations of 12 consulting officesthroughout North and South America. Mr. Lancaster worked with Schlumberger for six years following itsacquisition of S. A. Holditch & Associates, Inc. in October 1997. He joined S. A. Holditch & Associates in1980, and was one of the principals in that well-known petroleum engineering consulting firm. Between1980 and 1997, Mr. Lancaster held positions ranging from Senior Petroleum Engineer to Senior VicePresident — Business Development. In this latter role, he was responsible for marketing and sales, as wellas the company’s commercial training business. During most of his tenure at S. A. Holditch & Associates,Inc., Mr. Lancaster was a consulting reservoir engineer with particular emphasis on characterizing andimproving production from unconventional natural gas reservoirs. For more than seven years during thistime, he was the Project Manager for the Gas Research Institute’s Devonian Shales applied researchprojects investigating ways to improve reservoir characterization, completion practices and natural gasrecovery in low permeability, natural gas shale reservoirs. He was also the lead reservoir engineer for theSecondary Gas Recovery project sponsored by the Gas Research Institute and the U.S. Department ofEnergy looking at ways to improve recovery from compartmentalized natural gas reservoirs in north andsouth Texas. Mr. Lancaster began his career as a reservoir engineer for Diamond Shamrock Corporation in1979. Mr. Lancaster received Bachelor and Master of Science degrees in Petroleum Engineering from TexasA&M University in 1979 and 1988, respectively, graduating summa cum laude. He has authored orco-authored more than 50 technical papers and articles, as well as numerous other published reports andindustry presentations. He is a member of the Society of Petroleum Engineers, and he served as a chartermember and former Vice Chairman of the Texas A&M University Petroleum Engineering Advisory Board.Mr. Lancaster is a Licensed Professional Engineer in the State of Texas.

Mr. Matthew V. Hairford. Mr. Hairford joined Matador Resources Company in July 2004 as itsDrilling Manager. He was named Vice President — Drilling in May 2005; Vice President — Operations inMay 2006; and in May 2009 assumed the title of Executive Vice President— Operations. He is in charge ofour drilling and production operations. He was previously with Samson Resources, an exploration andproduction company, as Senior Drilling Engineer, having joined Samson in 1999. His responsibilities thereincluded difficult Texas and Louisiana Gulf Coast projects, horizontal drilling projects and a start-updrilling program in Wyoming. The scope of this work ranged from multi-lateral James Lime wells in eastTexas to deep wells in south Texas and south Louisiana. Mr. Hairford has drilled many geo-pressured wellsin Texas and Louisiana, along with normally pressured wells in southwestern Wyoming and east Texas.Additional responsibilities included a horizontal well program in Roger Mills County, Oklahoma at 15,000feet vertical depth. Mr. Hairford has experience in air drilling, underbalanced drilling, drilling under mudcaps and high temperature and pressure environments. From 1998 until 1999, Mr. Hairford served as SeniorDrilling Engineer with Sonat, Inc. in Tyler, Texas, a global company involved with natural gas transmissionand marketing, oil and natural gas exploration and production and oil services. There his responsibilitiesincluded Pinnacle Reef wells in east Texas and deep horizontal drilling in the Austin Chalk field in centralLouisiana. From 1984 to 1998, Mr. Hairford served in various drilling engineering capacities with Conoco,Inc., an integrated energy company. His operational areas included the Appalachian Basin, Illinois Basin,Permian Basin, Texas Panhandle and Val Verde Basin. Mr. Hairford was selected as a member of a three-person team to explore the use of unconventional technologies to identify a potential step change in thedrilling sector. Multiple techniques were evaluated and tested, including declassified defense departmenttechnologies. Additional Conoco assignments included both field and office drilling positions in Midlandand Oklahoma City. Earlier in his career with Conoco, Mr. Hairford was selected to participate in theConoco Rig Drilling Supervisor Training Program in Houston. This program consisted of two years

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working a regular rotation as a drilling representative on rigs and as a drilling engineer in various domesticoffices. Mr. Hairford began his career in 1984 with Conoco in a field production assignment in Hobbs, NewMexico. Mr. Hairford received his Bachelor of Science degree in Petroleum Engineering Technology fromOklahoma State University in 1984. He is an active member of the American Association of DrillingEngineers, the American Petroleum Institute and the Society of Petroleum Engineers. Mr. Hairford has alsoundertaken additional training through Stanford University’s Executive Education programs including, mostrecently in the summer of 2011, the Stanford Graduate School of Business flagship six week StanfordExecutive Program (SEP).

Mr. David F. Nicklin. Mr. Nicklin joined Matador Resources Company in February 2009 as ExecutiveDirector of Exploration, after working with us as an independent contractor since November 2007. Prior tojoining Matador, Mr. Nicklin provided executive level consulting services to a variety of clients fromJanuary 2000 onwards through his wholly owned corporation, David F. Nicklin International ConsultingInc. In 2006, Mr. Nicklin co-founded and currently leads a small, private oil and natural gas company, SaltCreek Petroleum LLC. Salt Creek Petroleum owns small, non-operated interests in a variety of onshore oiland natural gas fields in the United States. Since 2009, Mr. Nicklin has consulted almost exclusively for us,with the primary exception of the minimal time he has devoted to Salt Creek Petroleum. Mr. Nicklinworked approximately 210 days for us in each of 2009, 2010 and 2011. We have determined thatMr. Nicklin’s involvement with Salt Creek Petroleum does not detract from his performance for ourcompany and does not result in any conflict of interest between Mr. Nicklin and our company due to thefact that Salt Creek Petroleum is not involved in plays and prospects that compete with our interests. In2000, he founded and led for three years a private oil and natural gas exploration company, Serica Energy,which is now a public company with assets in Indonesia, the United Kingdom, Spain, Ireland and Morocco.Between 1981 and 2000, Mr. Nicklin was an employee of ARCO, an integrated energy company, where heparticipated in and led several international exploration teams, particularly in the Middle East, southeastAsia and Australasia. In 1991, he became the Chief Geologist for ARCO, a position he held until hisretirement in 2000. In this position, Mr. Nicklin was responsible for the quality of the geological effort atARCO, in particular, ensuring the application of state-of-the-art geological technology, the company’s riskmanagement process, the selection of new ventures and the high-grading of a large geoscience staff.Throughout his career at ARCO, Mr. Nicklin was closely involved with the successful exploration for anddevelopment of a number of large oil and natural gas discoveries. Prior to joining ARCO, Mr. Nicklin was asenior development and operations geologist in a variety of positions in the United Kingdom, Angola,Norway and the Middle East. He was a specialist in well-site operations and provided training in operationsto entry-level personnel. Mr. Nicklin was born in the United Kingdom and received a Bachelor of Sciencedegree in Geology from the University of Wales in 1971. He is an active member of the AmericanAssociation of Petroleum Geologists and various other professional groups.

Mr. Wade I. Massad. Mr. Massad joined Matador Resources Company in December 2011 as ExecutiveVice President—Capital Markets, after working as an independent contractor to the Matador Board ofDirectors since September 2010. Mr. Massad is the Co-Founder and Co-Managing Member of ClevelandCapital Management L.L.C., a registered investment advisor and General Partner of Cleveland Capital L.P.,a private investment fund focused on micro-cap public and private equity securities, since October 1996.Previously, Mr. Massad was an investment banker with Keybanc Capital Markets and RBC Capital Marketswhere he was the head of U.S equity institutional sales from 1997 to 1998 and the head of U.S CapitalMarkets business from 1999 to 2003. He also served on the firm’s executive committee at RBC. Mr.Massad has served on multiple public and private company boards and currently is a board member of4Kids Entertainment. Mr. Massad received a Bachelor of Arts in business management from Baldwin-Wallace College in 1989 and currently serves on its Board of Trustees.

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Mr. Scott E. King. Mr. King co-founded Matador Resources Company with Mr. Foran and serves asour Vice President — Geophysics and New Ventures. From July 2003 to February 2009, Mr. King held theposition of Vice President — Exploration, and in February 2009, he assumed his current position. He waspreviously with Matador Petroleum Corporation, joining that company in December 1996 as ChiefGeophysicist. Immediately prior to Matador Petroleum’s sale, Mr. King served as its Portfolio Manager andwas responsible for recommending which drilling opportunities Matador Petroleum should pursue. Prior tojoining Matador Petroleum, Mr. King worked for Enserch Corporation, a diversified energy company withinterests in petroleum exploration and production, oilfield services, engineering design and construction,and natural gas transmission and distribution, as Team Leader for the Oklahoma Asset Group. Mr. Kingbegan his career in 1983 with Sohio Petroleum, an integrated energy company. The Sohio assets were soldand resold to a number of companies, including BP p.l.c., Tex-Con Oil Co., Pacific Gas and ElectricCompany, Dalen Resources Oil & Gas Co., and finally Enserch Corporation. During this time, Mr. Kingworked for and was retained by each of these companies and had success in generating and managingdrilling opportunities in the continental United States. Mr. King received a Bachelor of Science degree inGeology with a Minor in Mathematics from Alfred University, Alfred, New York in 1981 and a Master ofScience degree in Geophysics from Wright State University, Dayton, Ohio in 1983. Mr. King is active invarious professional and civic groups including the American Association of Petroleum Geologists and theSociety of Exploration Geophysicists.

Mr. Bradley M. Robinson. Mr. Robinson joined Matador Resources Company in August 2003 as oneof its founders and has served as our Vice President — Reservoir Engineering since that time. Prior tojoining Matador, from 1997 to August 2003, Mr. Robinson held the position of Advisor with SchlumbergerLimited’s Data & Consulting Services business unit which provides full-field reservoir characterization,production enhancement, multidisciplinary reservoir and production solutions and field developmentplanning where he was responsible for the development and application of new technologies for wellcompletions and stimulation, provided technical expertise for reservoir management and field developmentprojects, taught basic and advanced industry courses in well completions and stimulation and providedinternal training in production engineering and stimulation methods. Mr. Robinson worked withSchlumberger for six years following its acquisition of S. A. Holditch & Associates, Inc. in 1997.Mr. Robinson joined Holditch in 1979, and was one of the principals in that well-known petroleumengineering consulting firm. From 1979 to 1982, Mr. Robinson served as Senior Petroleum Engineer andwas involved in all aspects of reservoir and production engineering for both conventional and lowpermeability oil and natural gas fields. From 1982 to 1997, he was Holditch’s Vice President — ProductionEngineering, where he was responsible for coordination and management of production and completionengineering projects, including development drilling and openhole data acquisition programs, design andsupervision of initial well completions and workovers, transient well test design and analysis and hydraulicfracture stimulation design and supervision. His duties also included reserves evaluation and economicanalysis of new and existing wells, and his areas of specialization included low permeability natural gassands, coalbed methane reservoirs, and horizontal wells. For approximately 10 years during this time, heserved as assistant project manager for the Gas Research Institute’s Tight Gas Sands and Horizontal GasWells applied research projects investigating ways to improve reservoir characterization, completionpractices and natural gas recovery in low permeability natural gas reservoirs and horizontal natural gaswells. During his career, he has worked all over the world including the United States, Canada, Venezuela,Colombia, Mexico, Egypt, the North Sea, Russia and Indonesia, among others. Mr. Robinson began hiscareer in 1977 with Marathon Oil Company, serving as an Associate Production Engineer and later as aReservoir Engineer in Midland. Mr. Robinson received Bachelor and Master of Science degrees inPetroleum Engineering from Texas A&M University in 1977 and 1986, respectively. He has authored orco-authored 18 technical articles appearing in industry and/or technical publications and has made

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numerous engineering technical presentations. Mr. Robinson is a member of the Society of PetroleumEngineers and is a Licensed Professional Engineer in the State of Texas.

Board of Directors

Our board of directors consists of eight directors. The following biographies describe the businessexperience of our directors, other than Mr. Foran. There are no family relationships among any of ourofficers and directors.

Mr. Charles L. Gummer. Mr. Gummer, age 65, joined our board of directors in September 2011. Hehas over 40 years of banking experience with Comerica Bank. From July 31, 2010 through October 31,2011, he was Chairman of Comerica Bank – Texas Market. From 1989 until July 31, 2010, he wasPresident and Chief Executive Officer of Comerica Bank – Texas. He earned his Bachelor of Sciencedegree from The Ohio State University and his Master of Business Administration from Wayne StateUniversity. He also graduated from the University of Michigan’s Graduate School of Banking and FinancialServices. In addition to his professional career with Comerica Bank, he has also been very involved in theDallas community, including as a current member of the Dallas Summer Musicals executive committee, theboard of Downtown Dallas, Inc., the executive board of the Southern Methodist University Cox School ofBusiness, the board of the Better Business Bureau of Dallas, the advisory board of the Vogel Alcove ArtsPerformance Committee, the advisory committee of the Greater Dallas Chamber of Commerce – EconomicDevelopment, the advisory committee of Bishop Lynch High School and the board of The CatholicFoundation. Mr. Gummer’s experience as a former Chairman, President and Chief Executive Officer and asenior executive of a publicly-traded bank, combined with his banking and mergers and acquisitionsexperience, plus his civic involvements provide our board of directors with extensive executive leadership,strategic planning, finance and general business expertise.

Dr. Stephen A. Holditch. Dr. Holditch, age 65, was a shareholder in and advisor to Matador PetroleumCorporation and is an original shareholder in Matador Resources Company. He was first elected to ourboard of directors in January 2004 and currently serves as chairman of the board’s Engineering Committee.He is a professor in the Harold Vance Department of Petroleum Engineering at Texas A&M University andis Head of the Texas A&M University Energy Institute. From January 2004 to January 2012, he was Headof the Harold Vance Department of Petroleum Engineering at Texas A&M University. Prior to that, he waswith Schlumberger Limited, a leading oilfield services provider, as a Fellow, one of only a handful oftechnical experts so recognized with this title in that company. In this position, Dr. Holditch advised topmanagement within Schlumberger Limited on production and reservoir engineering matters. Dr. Holditchjoined Schlumberger in 1997, following Schlumberger Limited’s acquisition of S. A. Holditch &Associates, Inc., the consulting company he founded and grew over 20 years into a preeminent engineeringfirm worldwide in the analysis of low permeability natural gas reservoirs and the design of hydraulicfracture treatments. During the latter half of the 1980’s and into the 1990’s, Dr. Holditch expanded theservices offered by S. A. Holditch & Associates, building the company from three employees in 1977 tomore than 80 employees in 1998. At the time of its sale to Schlumberger in 1997, S. A. Holditch &Associates had become a full-service petroleum engineering consulting company. From 1974 to 1976,Dr. Holditch worked as an independent consulting engineer on reservoir studies, well completions andfracture treatment design for numerous clients in east and south Texas. During that period, he also attendedTexas A&M University to earn a PhD degree in Petroleum Engineering and conducted research in reservoirflow behavior in fractured, low permeability natural gas reservoirs. From 1970 to 1974, he was a ProductionEngineer with Shell Oil Company, an integrated energy company, where his responsibilities includedproduction engineering for numerous oil and natural gas fields, well completions and massive hydraulic

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fracture treatment designs in several deep, geopressured fields in south Texas. From 1968 to 1969, heworked for Pan American Petroleum Corporation as a field engineer on various projects in east Texas.Dr. Holditch received Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&MUniversity in 1969 and 1970, respectively, and a PhD degree in Petroleum Engineering from Texas A&MUniversity in 1976. Dr. Holditch was President of the Society of Petroleum Engineers, International (SPE)in 2002 and served on the Society’s board of directors from 1998 to 2003. In addition, he served as aTrustee for the American Institute of Mining, Metallurgical, and Petroleum Engineers from 1997 to 1998.He was also on the board of directors of Triangle Petroleum Corporation, an oil and natural gas explorationcorporation, from February 2006 to December 2011. He has received numerous awards in recognition of histechnical achievements and leadership. In 1995, Dr. Holditch was elected to the National Academy ofEngineering, the highest professional honor awarded to an engineer. In 1997, he was elected to the RussianAcademy of Natural Sciences, and in 1998, Dr. Holditch was elected to the Petroleum EngineeringAcademy of Distinguished Graduates at Texas A&M University and was recently named distinguishedalumnus of engineering. Dr. Holditch received the SPE Distinguished Service Award for PetroleumEngineering Faculty in 1981 and held the Shell Distinguished Chair in Petroleum Engineering at TexasA&M University from 1983 to 1987. He was awarded the R. L. Adams Professorship in 1995. He teachesgraduate level courses in formation evaluation, well stimulation and production engineering, and hasactively performed and supervised research at Texas A&M University since 1974 in a wide range ofengineering areas. Dr. Holditch is a member of numerous professional societies and serves as a boardmember and/or trustee for several business affiliations. He has been an SPE Distinguished Lecturer and hasco-authored or edited three books and more than 100 technical papers; he has made more than 80 invitedtechnical presentations to petroleum industry audiences. His position as Professor and Head of the HaroldVance Department of Petroleum Engineering at Texas A&M University, his prior positions withSchlumberger and S. A. Holditch & Associates, Inc. and his prior service on the board of directors ofTriangle Petroleum Corporation provide our board of directors with additional perspective on ourcompletion and stimulation operations and other business and engineering matters.

Mr. David M. Laney. Mr. Laney, age 62, is an original shareholder in Matador Resources Company andwas an original shareholder in Matador Petroleum Corporation. He was one of the original directors on ourboard of directors in July 2003 and currently serves as lead independent director and chairman of the board’sNominating, Compensation and Planning Committee. He is an attorney who since March 2007 has practicedlaw as a solo practitioner. Between 2003 and 2007, he was a partner with the law firm of Jackson Walker LLPin Dallas where he practiced in the area of corporate and financial law. Prior to joining Jackson Walker,Mr. Laney practiced at the law firm of Jenkens & Gilchrist, a Professional Corporation, from 1977 to 2003 andwas managing partner of the Jenkens & Gilchrist law firm from 1990 to 2002. During his tenure as ManagingPartner, Jenkens & Gilchrist was recognized as one of the fastest growing firms in the country and was namedby industry press as among the top 50 firms in the country (from the standpoint of size and financialperformance). From a regional law firm of roughly 160 lawyers in two Texas cities in 1990, the firm expandedunder Mr. Laney’s leadership to over 625 attorneys in nine cities by the end of his tenure in 2002. Mr. Laneyhas also served in several capacities as an appointee of Texas Governors William Clements and George W.Bush on various state boards continuously from 1989 through 2001. He was Governor Clements’ appointee tothe Texas Finance Commission, responsible for regulatory oversight of the state banking and thrift industriesas the Texas banking system emerged from the recession and collapse of the 1980’s. He then served asGovernor Bush’s Texas Commissioner of Transportation (Chairman of the Texas Department ofTransportation) during the period 1995 to 2000. Mr. Laney completed his term with the Texas Department ofTransportation (TxDOT) in 2001. As Commissioner of Transportation, his responsibilities were largely thoseof the chief executive of TxDOT, a 14,000 employee state agency with a $5 billion annual budget. In thatposition, he initiated and oversaw the planning and successful execution of an extensive number of

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organizational and operational innovations throughout the organization, and developed and managed TxDOT’slegislative agenda during three regular sessions of the Texas Legislature. In 2002, Mr. Laney was nominatedby President George W. Bush to the board of directors of Amtrak and confirmed by the U. S. Senate for a five-year term. In November 2007, he completed his term as Chairman of Amtrak’s board of directors. From 1998to 2003, Mr. Laney served as a member of the Stanford University Board of Trustees, and for two years asChairman of its Audit Committee. Mr. Laney has also served in various capacities in connection withnumerous civic and educational organizations and projects in the Dallas area. Mr. Laney’s legal experience andleadership positions in governmental departments provide our board of directors with additional perspective onour corporate governance, legal and governmental relations matters and general business matters.

Mr. Gregory E. Mitchell. Mr. Mitchell, age 60, joined our board of directors in June 2011. With 45years of grocery and petroleum retailing experience, he is currently President and CEO of Toot’n TotumFood Stores, LLC, his family company, which is located in Amarillo, Texas. The company, founded in1950, consists of 62 convenience store/fueling locations, as well as car wash and car care centers, with anemployee base of over 700 team members. His experience within the petroleum industry includes extensivenegotiations with various major refiners in the United States. A 1973 graduate of the University ofOklahoma, with a Bachelor of Business Administration degree, Mr. Mitchell was appointed by formerGovernor William Clements to the Texas Higher Education Coordinating Board, where he served for sixyears. Additionally, he has served as Chairman of the Amarillo Chamber of Commerce, Chairman of theUnited Way of Amarillo and Canyon, Chairman of the Don and Sybil Harrington Foundation and Presidentof the Amarillo Area Foundation. Currently, Mr. Mitchell is a director of Cal Farley’s Boys Ranch. Mr.Mitchell’s experience as President and CEO of his large family business and as a director of severalcompanies in the past provides our board of directors with extensive business, strategic and executiveleadership experience.

Dr. Steven W. Ohnimus. Dr. Ohnimus, age 65, was first elected to our board of directors in January2004 and currently serves as chairman of the board’s Operations Committee. He spent his entireprofessional career from 1971 to 2000 with Unocal Corporation, an integrated energy company. From 1995to 2000, he was General Manager — Partner Operated Ventures, where he represented Unocal’snon-operated international interests at board meetings, management committees and other high levelmeetings involving projects in the $200 million range in countries such as Azerbaijan, Bangladesh, China,Congo, Myanmar and Yemen. From 1994 to 1995, Dr. Ohnimus was General Manager of Asset Analysis,where he managed and directed planning, business plan budgeting and scenario plans for the domestic andinternational business unit with an asset portfolio totaling $5.5 billion. From 1990 to 1994, Dr. Ohnimuswas Vice President and General Manager, Unocal Indonesia, located in Balikpapan, operating five offshorefields and one onshore liquid extraction plant and employing 1200 nationals and 50 expatriates. From 1989to 1990, he served as Regional Operations Manager in Anchorage, Alaska, and from 1988 to 1989, he wasDistrict Operations Manager in Houma, Louisiana. From 1981 to 1988, Dr. Ohnimus was in variousmanagement assignments in Houston and Houma, Louisiana, and from 1971 to 1981 he handled varioustechnical assignments in reservoir, production and drilling in the Gulf Coast area (Houston, Van, Lafayetteand Houma). From 1975 to 1979, Dr. Ohnimus was Assistant Professor of Petroleum Engineering at theUniversity of Southwest Louisiana (now University of Southern Louisiana) where he taught a total ofeleven undergraduate and graduate night classes. In 1980, he taught drilling seminars at the University ofTexas Petroleum Extension Service of the International Association of Drilling Contractors (IADC).Dr. Ohnimus has authored several published papers concerning reservoir recompletion and increasedrecovery. Dr. Ohnimus received his Bachelor of Science degree in Chemical Engineering from theUniversity of Missouri at Rolla in 1968, a Master of Science degree in Petroleum Engineering from theUniversity of Missouri at Rolla in 1969 and a PhD degree in Petroleum Engineering from the University of

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Missouri at Rolla in 1971. Dr. Ohnimus served as a director of the American Petroleum Institute in 1978and 1979, served as Session Chairman for the Society of Petroleum Engineers’ Annual Convention in 1982,was the Evangeline Section Chairman of the Society of Petroleum Engineers in 1978 and 1979 and servedas President of the Unocal Credit Union from 1986 to 1988. In 2007, he was elected President of the UnocalGulf Coast Alumni Club, which reports through the Chevron Retirees Association. He still holds thatposition. In June 2008, Dr. Ohnimus was elected as the vice chairman of the advisory board of WesternStandard Energy Corp. (OTCBB:WSEG), an oil and natural gas exploration company. Due to his long oiland natural gas industry career and significant operational and international experience, Dr. Ohnimusprovides valuable insight to our board of directors on our drilling and completion operations andmanagement, as well as providing a global technology and operations perspective.

Mr. Michael C. Ryan. Mr. Ryan, age 51, joined our board of directors in February 2009 and currentlyserves as chairman of the board’s Audit Committee. Prior to joining the board, he served as a BoardAdvisor to the Financial Committee and frequently participated in board planning and strategy sessions.Since October 2004, Mr. Ryan has been a Partner and member of the Investment Committee at BerensCapital Management LLC, an investment firm based in New York. From February 1998 to June 2004, heworked with Goldman, Sachs & Co., a global investment banking and securities services firm, leading itsWest Coast international institutional equities business. In this role, he developed and built a team ofprofessionals to advise large institutional clients on their global investment decisions. From 1995 to 1998,Mr. Ryan lived in Oslo, Norway, where he was a Partner at Pareto Securities, a Scandinavian-basedsecurities firm where he led and built the institutional equities business into the United States and UnitedKingdom. From 1991 to 1994, Mr. Ryan represented multiple eastern European governments in thepreparation, negotiation and sale of many of their largest state-owned companies. He began his career withHoneywell, Inc. which invents and manufactures technologies, including in the safety, security and energyareas, in 1983, working in the Systems and Research Center, which focused on advanced weaponsdevelopment programs. Mr. Ryan received a Master of Business Administration degree from The WhartonSchool at the University of Pennsylvania and a Bachelor of Science degree from the University ofMinnesota. Mr. Ryan’s background and experience in the domestic and international financial worldprovide our board of directors with additional perspective on accounting and auditing functions, economictrends and our capital sourcing and financing opportunities.

Mrs. Margaret B. Shannon. Mrs. Shannon, age 62, joined our board of directors in June 2011 andcurrently serves as chairperson of the board’s Corporate Governance Committee. She served as Vice Presidentand General Counsel of BJ Services Company, an international oilfield services company, from 1994 to 2010,when Baker Hughes Incorporated acquired BJ Services. Prior to 1994, she was a partner with the law firm ofAndrews Kurth LLP. Mrs. Shannon is active in community activities serving as the Chair of the MembershipCommittee of the board of directors of the Harris County Health Alliance and a member of the board ofdirectors of the Harris County Health and Human Services Foundation. She previously served as the Chair ofthe Executive Women’s Partnership sponsored by the Greater Houston Partnership, Chair of the AuditCommittee of the board of directors of the South Texas College of Law and the chair of the Endowment Boardof Palmer Memorial Episcopal Church and was a participant in the American Leadership Forum.Mrs. Shannon received her J.D. cum laude from Southern Methodist University Dedman School of Law in1976 and her Bachelor of Arts degree from Baylor University in 1971. Mrs. Shannon’s experience as anattorney, as a partner with Andrews Kurth LLP, as general counsel for a public company for more than 15years and as a director for numerous other organizations provides our board of directors with importantinsights into public company obligations, corporate governance and board functions.

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Although our bylaws include a mandatory retirement age of 70 for directors, our board of directors ispermitted to waive such restriction on an annual basis up to age 75 upon the determination by the board thatsuch waiver is in the best interest of the company.

In addition, our board is divided into three classes of directors, designated Class I, Class II and Class III,with the term of office of each director ending on the date of the third annual meeting following the annualmeeting at which such director was elected. The numbers of directors in each class will be as nearly equal aspossible at all times. The current Class I directors are Mrs. Shannon and Messrs. Gummer and Ryan, who willhold office until the 2012 annual meeting of shareholders and until the election and qualification of theirrespective successors or until their earlier death, retirement, resignation or removal. The current Class IIdirectors are Mr. Mitchell and Dr. Ohnimus, who will hold office until the 2013 annual meeting ofshareholders and until the election and qualification of their respective successors or until their earlier death,retirement, resignation or removal. The current Class III directors are Messrs. Foran and Laney andDr. Holditch, who will hold office until the 2014 annual meeting of shareholders and until the election andqualification of their respective successors or until their earlier death, retirement, resignation or removal.

Special Board Advisors

In addition to our board of directors, we have three individuals who have significant oil and gasexperience or legal, accounting and other business experience who advise our board of directors on variousmatters. Other than indemnification agreements in form similar to those entered into with our directors andofficers, we have not entered into written agreements with these individuals with respect to their service asspecial advisors to our board of directors. Their business histories are described below:

Mr. Marlan W. Downey. Mr. Downey worked for Shell Oil Company, an integrated energy company,from 1957 to 1987. In 1977, he moved to Shell Oil’s International Exploration & Production business andbecame Vice President of Shell, and then President of Shell Oil’s newly-formed international subsidiary,Pecten International. Mr. Downey joined ARCO International in 1990 as Senior Vice President ofExploration, becoming President of ARCO International and then Senior Vice President and ExecutiveExploration Advisor to ARCO International. Mr. Downey retired from ARCO in 1996. He is a fellow of theAmerican Association for the Advancement of Science. Mr. Downey is a past President of the AmericanAssociation of Petroleum Geologists (“AAPG”) and is Chief Scientist — Sarkeys Energy Center atOklahoma University. Mr. Downey is the 2009 recipient of the AAPG’s Sidney Powers Medal, which is thehighest honor awarded by the AAPG. He is also active in several international scientific organizations andserves on boards of the Institute for the Study of Earth and Man, and the Reves Institute for InternationalStudies at William and Mary. Mr. Downey received a Bachelor of Arts degree in Chemistry in 1952 at PeruState College in Nebraska. He served in the Army in Korea and the Philippines, then entered graduateschool at the University of Nebraska, and received a Bachelor of Science degree in 1956 and a Master ofScience degree in Geology in 1957. Mr. Downey previously served on Matador Petroleum Corporation’sboard of directors with Mr. Foran. He has served as a special advisor since our inception in July 2003 andcurrently serves as chairman of the board’s Prospect Committee.

Mr. Edward R. Scott, Jr. Mr. Scott is a successful Amarillo, Texas lawyer, civic leader andbusinessman, managing a varied portfolio of real estate and development-related concerns. Currently, he isthe primary developer for two residential developments in Amarillo: Pheasant Run and The Greenways. Heserves as primary owner of Document Shredding & Storage which services the entire Panhandle area,Sparky’s Storage Solutions in Amarillo, Texas and is part owner in several car washes in the Lubbock,Abilene and Dallas/Fort Worth areas. From 1968 to 1996, Mr. Scott was an attorney with the Amarillo lawfirm of Gibson, Ochsner & Adkins. From 1965 to 1968, he served as an accountant with Price

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Waterhouse & Co. Mr. Scott received his Bachelor of Business Administration degree in Accounting fromWest Texas State University in 1962 and an LLB from The University of Texas School of Law in 1965.Mr. Scott has previously served as a director and chairman of the Amarillo Economic DevelopmentCorporation and is currently serving as a board member of the Salvation Army, Amarillo Area Foundation,as well as the Amarillo Club. He is a past President of the Rotary Club of Amarillo, the AmarilloBusinessmen’s Club, the Amarillo Club, Big Brothers and Big Sisters and the Amarillo BusinessFoundation. He is a former chairman of the Amarillo Board of City Development and a former member ofthe Board of Regents for West Texas State University. Mr. Scott has previously served as an officer and/orboard member to many other local civic and/or charitable organizations. He is a member of the Texas BarAssociation, the Amarillo Bar Association, the Texas Society of Certified Public Accountants and thePanhandle Chapter of the Texas Society of Certified Public Accountants. Mr. Scott is an originalshareholder in both Matador Resources Company and the former Matador Petroleum Corporation. He wasan original director on the Matador Resources Company board of directors and served as chairman of theAudit Committee for eight years until his retirement from the board in June 2011.

Mr. W.J. “Jack” Sleeper, Jr. Mr. Sleeper has over 55 years of experience evaluating oil and gasproperties. Mr. Sleeper joined DeGolyer and MacNaughton, a petroleum consulting firm, as a PetroleumEngineer in 1965. He performed numerous field studies in North and South America, the North Sea and theMiddle East. Mr. Sleeper retired as President and Chief Operating Officer of DeGolyer and MacNaughtonon January 1, 1995. He served on DeGolyer and MacNaughton’s board of directors from 1978 until hisretirement. Upon his graduation from the University of Oklahoma with a Bachelor of Science degree inPetroleum Engineering (with Distinction) in 1955, he was employed by Shell Oil Company, an integratedenergy company, as an Exploitation Engineer. During his 10 years with Shell he spent three yearsperforming research at Shell Development Company in the fields of Reservoir Engineering, Geology andPetrophysics. He held the titles of Project Engineer, Senior Exploitation Engineer and Senior ProductionGeologist during his tenure with Shell. Mr. Sleeper has served on the Mewborne Petroleum and GeologicalBoard of Advisors at the University of Oklahoma since 1995. He is a Licensed Professional Engineer(retired) in the states of Oklahoma and Texas. Mr. Sleeper previously served on Matador PetroleumCorporation’s board of directors with Mr. Foran. He has served as a special advisor since our inception inJuly 2003.

Committees of the Board of Directors

We have an Audit Committee, Nominating, Compensation and Planning Committee, CorporateGovernance Committee, Executive Committee, Operations Committee, Engineering Committee, FinancialCommittee and Prospect Committee and may have such other committees as the board of directors shalldetermine from time to time. The charters of each of the Audit Committee, Nominating, Compensation andPlanning Committee and Corporate Governance Committee will be available on our website atwww.matadorresources.com concurrently with, or prior to, the completion of this offering. Each of thestanding committees of the board of directors have the composition and responsibilities described below.

Audit Committee

The Audit Committee assists the board of directors in monitoring:

• the integrity of our financial statements and disclosures;

• our compliance with legal and regulatory requirements;

• the qualifications and independence of our independent auditor;

• the performance of our internal audit function and our independent auditor; and

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• our internal control systems.

In addition, the Audit Committee is charged with the compliance of our Code of Ethics and BusinessConduct for Officers, Directors and Employees.

Our Audit Committee currently consists of Messrs. Gummer, Laney, Mitchell and Ryan and Dr. Ohnimus,each of whom is independent under the rules of the NYSE and the SEC. Mr. Ryan is the chairman of the AuditCommittee. SEC rules require a public company to disclose whether or not its audit committee has an “auditcommittee financial expert” as a member. An “audit committee financial expert” is defined as a person who,based on his or her experience, possesses the attributes outlined in such rules. Our board of directors hasdetermined that Messrs. Gummer and Ryan are each “audit committee financial experts.”

Nominating, Compensation and Planning Committee

The Nominating, Compensation and Planning Committee has the following responsibilities:

• identify and recommend to the board of directors individuals qualified to be nominated for electionto the board of directors;

• recommend to the board of directors the members and chairman of each committee of the board ofdirectors;

• assist the board of directors and the independent members of the board of directors in the dischargeof their fiduciary responsibilities relating to the fair and competitive compensation of our executiveofficers;

• provide overall guidance with respect to the establishment, maintenance and administration of ourcompensation programs, including stock and benefit plans;

• oversee and advise the board of directors and the independent members of the board of directors onthe adoption of policies that govern our compensation programs; and

• recommend to the board of directors the strategy, tactical and performance goals of the company,including those performance and tactical goals that relate to performance based compensation,including but not limited to goals for production, reserves, cash flows and shareholder value.

Our Nominating, Compensation and Planning Committee currently consists of Mrs. Shannon andMessrs. Gummer, Laney, Mitchell and Ryan and Drs. Holditch and Ohnimus, each of whom is independentunder the rules of the NYSE, a “non-employee director” pursuant to Section 16(b) of the SecuritiesExchange Act of 1934, as amended, or the Exchange Act, and an “outside director” pursuant toSection 162(m) of the Internal Revenue Code of 1986, as amended. Mr. Laney is the chairman of theNominating, Compensation and Planning Committee.

The board of directors has also established a Director Nominating Advisory Committee that is chargedwith receiving and considering possible nominees for election by shareholders to the board of directors.Pursuant to the Director Nominating Advisory Committee charter, this committee will be comprised of 8 to 12persons selected by the Nominating, Compensation and Planning Committee, and will consist of at least:

• two members of the Nominating, Compensation and Planning Committee;

• two former members of or special advisors to the board of directors;

• two shareholders who beneficially own common stock having a market value of at least $1.0million (such value to be based on the market value of the common stock immediately prior todesignation of such shareholders to the Director Nominating Advisory Committee); and

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• two shareholders who have beneficially owned common stock continuously for at least the fiveyears prior to such shareholders’ designation to the Director Nominating Advisory Committee.

The Director Nominating Advisory Committee will make recommendations on its conclusions to theNominating, Compensation and Planning Committee for its consideration and review.

Corporate Governance Committee

The Corporate Governance Committee is responsible for periodically reviewing and assessing ourcorporate governance guidelines and making recommendations for changes thereto to the board of directors,reviewing any other matters related to our corporate governance, unless the authority to conduct suchreview has been retained by the board of directors or delegated to another committee and overseeing theevaluation of the board of directors and management.

Our Corporate Governance Committee currently consists of Mrs. Shannon and Messrs. Gummer,Laney and Mitchell, each of whom is independent under the rules of the NYSE. Mrs. Shannon ischairperson of the Corporate Governance Committee.

Executive Committee

The Executive Committee has authority to discharge all the responsibilities of the board of directors inthe management of the business and affairs of the company, except where action of the full board ofdirectors is required by statute or by our certificate of formation.

Our Executive Committee consists of Messrs. Foran and Laney and Dr. Ohnimus, and Mr. Foran ischairman of the Executive Committee.

Operations Committee

We have, and anticipate continuing to have upon completion of this offering, an OperationsCommittee. The Operations Committee provides oversight over the development of our prospects, ourdrilling and completion operations and our production operations and associated costs. The current membersof the Operations Committee are Messrs. Foran and Sleeper (ex-officio) and Drs. Holditch and Ohnimus,and Dr. Ohnimus is chairman of the Operations Committee.

Engineering Committee

We have, and anticipate continuing to have upon completion of this offering, an EngineeringCommittee. The Engineering Committee provides oversight over the amount and classifications of ourreserves and the design of our completion techniques and hydraulic fracturing operations and various otherreservoir engineering matters. The current members of the Engineering Committee are Messrs. Foran,Downey (ex-officio) and Sleeper (ex-officio) and Drs. Holditch and Ohnimus, and Dr. Holditch is chairmanof the Engineering Committee.

Financial Committee

We have, and anticipate continuing to have upon completion of this offering, a Financial Committee.The Financial Committee provides oversight over our financial position, liquidity and capital needs and thevarious methods for financing our business. The current members of the Financial Committee are Messrs.Foran, Gummer, Laney, Mitchell and Ryan, and Mr. Foran is chairman of the Financial Committee.

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Prospect Committee

We have, and anticipate continuing to have upon completion of this offering, a Prospect Committee. TheProspect Committee provides oversight over the technical analysis, evaluation and selection of our oil andnatural gas prospects. The current members of the Prospect Committee are Messrs. Foran, Downey andSleeper (ex-officio) and Drs. Holditch and Ohnimus, and Mr. Downey is chairman of the Prospect Committee.

Nominating, Compensation and Planning Committee Interlocks and Insider Participation

No member of our Nominating, Compensation and Planning Committee is an employee of theCompany. None of our executive officers serve on the board of directors or compensation committee of acompany that has an executive officer that serves on our board of directors or Nominating, Compensationand Planning Committee. No member of our board of directors serves as an executive officer of a companyin which one of our executive officers serves as a member of the board of directors or compensationcommittee of that company.

To the extent any members of our Nominating, Compensation and Planning Committee and affiliatesof theirs have participated in transactions with us meeting the requirements of Item 404 of Regulation S-K,a description of those transactions is described in “Certain Relationships and Related Party Transactions.”

Code of Ethics and Business Conduct for Officers, Directors and Employees

Our board of directors has adopted a Code of Ethics and Business Conduct for Officers, Directors andEmployees that complies with applicable U.S. federal securities laws and the corporate governance rules ofthe NYSE. Any waiver of this code may be made only by our officer responsible for monitoring compliancewith such code (or Audit Committee in certain circumstances) and if required by applicable U.S. federalsecurities laws or the corporate governance rules of the NYSE will be promptly disclosed. A copy of theCode of Ethics and Business Conduct for Officers, Directors and Employees will be posted on our websiteconcurrently with, or prior to, the completion of this offering.

Corporate Governance Guidelines

Our board of directors has adopted corporate governance guidelines in accordance with the corporategovernance rules of the NYSE. A copy of the corporate governance guidelines will be posted on ourwebsite concurrently with, or prior to, the completion of this offering.

Director Independence

Our board of directors has reviewed the independence of our directors and considered whether anydirector has a material relationship with us that could compromise his or her ability to exercise independentjudgment in carrying out his or her responsibilities. After this review, our board of directors determined thatthe following directors are “independent directors” as defined under the rules of the SEC and the NYSE:Mrs. Shannon, Messrs. Gummer, Laney, Mitchell and Ryan, and Drs. Holditch and Ohnimus.

Lead Independent Director

Our corporate governance guidelines provide that one of our independent directors should serve as a leadindependent director at any time when the chief executive officer serves as the chairman of the board. The leadindependent director presides over executive sessions of our independent directors, serves as a liaison betweenour chairman and the independent directors and performs such additional duties as our board of directors mayotherwise determine and delegate. Because Mr. Foran serves as Chairman of the Board and Chief ExecutiveOfficer, our independent directors have appointed Mr. Laney to serve as lead independent director.

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COMPENSATION OF NAMED EXECUTIVE OFFICERS

Compensation Discussion and Analysis

In this compensation discussion and analysis, we discuss our compensation objectives, our decisionsand the rationale behind those decisions relating to compensation for 2011 for our principal executiveofficer, our principal financial officer, our other three most highly compensated executive officers andWade I. Massad, our new Executive Vice President — Capital Markets. Furthermore, this compensationdiscussion and analysis discusses our decisions to date regarding compensation for 2012 and the rationalebehind those decisions. This compensation discussion and analysis provides a general description of ourcompensation program and specific information about its various components.

Named Executive Officers

Throughout this discussion, the following individuals are referred to as the “Named ExecutiveOfficers” and are included in the Summary Compensation Table:

• Joseph Wm. Foran, Chairman of the Board, Chief Executive Officer and President;

• David E. Lancaster, Executive Vice President, Chief Operating Officer and Chief FinancialOfficer;

• Matthew V. Hairford, Executive Vice President — Operations;

• Wade I. Massad, Executive Vice President — Capital Markets;

• David F. Nicklin, Executive Director of Exploration; and

• Bradley M. Robinson, Vice President — Reservoir Engineering.

Objectives of Our Compensation Program

Our future success and the ability to create long-term value for our shareholders depends on our abilityto attract, retain and motivate highly qualified individuals in the oil and natural gas industry. Additionally,we believe that our success also depends on the continued contributions of our Named Executive Officers.Our executive compensation program is designed to provide a comprehensive compensation program tomeet the following objectives:

• to be fair to both the executive and the company;

• to attract and retain talented and experienced executives with the skills necessary for us to executeour business plan;

• to provide opportunities to achieve a total compensation level that is competitive with comparablepositions at companies with which we compete for executives;

• to align the interests of our executive officers with the interests of our shareholders and with theperformance of our company for long-term value creation;

• to provide financial incentives to our executives to achieve our key corporate and individualobjectives;

• to provide an appropriate mix of fixed and variable pay components to establish a“pay-for-performance” oriented compensation program;

• to foster a shared commitment among executives by coordinating their corporate and individualgoals;

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• to provide compensation that takes into consideration the education, professional experience andknowledge that is specific to each job and the unique qualities the executive provides; and

• to recognize an executive’s commitment and dedication in his job performance and in support ofour culture.

What Our Compensation Program Is Designed to Reward

Our compensation program is designed to reward, in both the short-term and the long-term,performance that contributes to the implementation of our business strategies, maintenance of our cultureand values and the achievement of our objectives. In addition, we reward qualities that we believe helpachieve our business strategies such as teamwork; individual performance in light of general economic andindustry-specific conditions; relationships with shareholders and vendors; the ability to manage and enhanceproduction from our existing assets; the ability to explore new opportunities to increase oil and natural gasproduction; the ability to identify and acquire additional acreage; the ability to increase year-over-yearproved reserves; the ability to control unit production costs; level of job responsibility; industry experience;and general professional growth.

2011

Elements of Our 2011 Compensation Program and Why We Paid Each Element

For 2011, our management compensation program was comprised of the following three elements:

• Base Salary. We paid base salary to reward an executive for his assigned responsibilities,experience, leadership and expected future contribution.

• Discretionary Cash Bonus. We included a discretionary cash bonus as part of our managementcompensation program because we believed this element of compensation (i) helped focus andmotivate management to achieve key corporate and individual objectives by rewarding theachievement of these objectives; (ii) helped retain management; (iii) rewarded our successes overthe prior year; and (iv) was necessary to be competitive from a total remuneration standpoint.

• Benefits. We offered a variety of health and welfare programs to all eligible employees, includingthe executive officers other than Mr. Nicklin. The health and welfare programs were intended toprotect employees against catastrophic loss and encourage a healthy lifestyle.

In addition, in prior years, we used stock options as the primary vehicle for (i) linking our long-termperformance and increases in shareholder value to the total compensation for our executive officers and(ii) providing competitive compensation to attract and retain our executive officers. Due to the timing of thisoffering, we did not issue any stock options in 2011.

How We Determined Each Element of 2011 Compensation

In the first part of 2011, we had a Planning and Compensation Committee (a predecessor committee tothe Nominating, Compensation and Planning Committee), and in consideration of becoming a publiccompany and in connection with this offering, the Planning and Compensation Committee engaged PayGovernance LLC as its independent executive compensation advisory firm to assist with the developmentand implementation of a new executive compensation program which we originally anticipated wouldbecome effective upon the completion of this offering.

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For purposes of benchmarking executive compensation, Pay Governance LLC developed a list ofrecommended peer companies in the oil and gas exploration and production sector. These companies wererecommended to and approved by the Planning and Compensation Committee based on their annualrevenues, market capitalization, enterprise value, total assets and EBITDA (earnings before interest, taxes,depletion, depreciation and amortization). The 2011 compensation peer companies are as follows:

Bill Barrett Corp. Petroleum Development Corp.Breitburn Energy Partners, L.P. Rosetta Resources, Inc.Clayton Williams Energy Inc. Stone Energy Corp.Comstock Resources Inc. Swift Energy Co.Contango Oil & Gas Co. Unit CorporationGulfport Energy Company Venoco, Inc.Penn Virginia Corp. W&T Offshore, Inc.

Mr. Foran was compared against the chief executive officer position of all 14 peer companies.Mr. Lancaster was compared against the average of the chief financial officer position and the secondhighest paid position based on annual cash compensation of the 14 peer companies. Messrs. Hairford,Nicklin and Robinson were compared against the third, fourth and fifth highest paid positions based onannual cash compensation of the peer companies, respectively. However, Gulfport Energy Company did nothave a fourth and fifth highest paid position and Contango Oil and Gas Co. and Venoco Inc. did not have afifth highest paid position. The data regarding the peer comparison is based on information presented intheir 2010 filings regarding compensation for the year ended December 31, 2009 except for Contango Oiland Gas Co., which had a June 30, 2010 year-end.

As an overall compensation philosophy for 2011, we decided to adopt conservative pay levels as aninitial strategy of being a public company. As we grow and build value for our shareholders throughsustained high performance and shareholder returns, we plan to increase our overall compensation paylevels gradually toward the 50th percentile of our peer group. In developing our public companycompensation program for 2011, we adopted a strategy of focusing on the 25th percentile (lowest quartile)as a general target range for benchmarking most of our Named Executive Officer compensation. Initially for2011, all elements of direct compensation, including base salary, annual incentive compensation and long-term incentive compensation were targeted for most of our Named Executive Officers to provide payopportunities in the range of the 25th percentile of our peer companies; however, as described below, basedon the timing of this offering, the Nominating, Compensation and Planning Committee and the IndependentDirectors (as defined below) (both of which are currently comprised of the same members) modified thetiming of the increases in certain base salaries, determined not to use a formulaic cash incentive program for2011 and determined not to make any equity grants to Named Executive Officers for 2011.

2011

Nominating, Compensation and Planning Committee

In consideration of becoming a public company, in August 2011, we formed the Nominating,Compensation and Planning Committee of our board of directors and adopted a charter for such committeewhich provides a new process for approving compensation of the Named Executive Officers. TheNominating, Compensation and Planning Committee has the authority at our expense to retain andterminate independent third-party compensation consultants and other expert advisors. In addition, theNominating, Compensation and Planning Committee will confirm at least annually that our incentive paydoes not encourage unnecessary risk taking and review and discuss the relationship between riskmanagement policies and practices, corporate strategy and senior executive compensation.

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With regard to all of the Named Executive Officers, the Nominating, Compensation and PlanningCommittee will recommend to the independent members of our board of directors (the “IndependentDirectors”):

• option guidelines and size of overall grants;

• option grants and other equity and non-equity related awards; and

• modifications or cancellations of existing grants and substitutions of new grants.

The Independent Directors are required to be independent pursuant to the listing standards of theNYSE and the rules and regulations promulgated under the Exchange Act and Section 162(m) of theInternal Revenue Code of 1986, as amended (the “Code”).

The Nominating, Compensation and Planning Committee will annually review and makerecommendations to the Independent Directors regarding the matters related to Mr. Foran’s compensationincluding corporate goals and objectives applicable to Mr. Foran’s compensation. The Nominating,Compensation and Planning Committee will also evaluate Mr. Foran’s performance in light of theseestablished goals and objectives at least annually. Based upon these evaluations, the Nominating,Compensation and Planning Committee will make recommendations to the Independent Directors regardingMr. Foran’s annual compensation, including salary, bonus and equity and non-equity incentivecompensation. The Nominating, Compensation and Planning Committee will review and recommend to theIndependent Directors with regard to Mr. Foran:

• any employment agreement, severance agreement, change in control agreement or provision orseparation agreement or amendment thereof;

• any deferred compensation arrangement or retirement plan or benefits; and

• any benefits and perquisites.

On an annual basis, after consultation with Mr. Foran, the Nominating, Compensation and PlanningCommittee will review and make recommendations to the Independent Directors on the evaluation processand compensation structure for the other Named Executive Officers. After considering the evaluation andrecommendations of Mr. Foran, the Nominating, Compensation and Planning Committee will evaluate theperformance of the other Named Executive Officers and make recommendations to the IndependentDirectors regarding the annual compensation of such Named Executive Officers, including salary, bonusand equity and non-equity incentive compensation.

After considering the recommendations of Mr. Foran with regard to the other Named ExecutiveOfficers, the Nominating, Compensation and Planning Committee will review and recommend to theIndependent Directors regarding the other executive officers:

• any employment agreement, severance agreement, change in control agreement or provision orseparation agreement or amendment thereof;

• any deferred compensation arrangement or retirement plan or benefits; and

• any benefits and perquisites.

In addition, pursuant to its charter, the Nominating, Compensation and Planning Committee willreview and recommend to the Independent Directors any proposals for the adoption, amendment,modification or termination of our incentive compensation, equity based plans and non-equity based plans.

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2011 Base Salary

Based on the recommendations of Mr. Foran and Mr. Laney, the chairman of the Planning andCompensation Committee, the Planning and Compensation Committee (which consisted of Messrs. Foran,Laney, Ryan and Scott and Dr. Holditch) and the board of directors (other than Mr. Foran) decided that formost of 2011, except for Mr. Robinson, the base salaries for our Named Executive Officers would remain attheir 2010 levels which were as follows:

Executive Officer 2010 Base Salary

Joseph Wm. Foran . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $240,000Chairman of the Board, Chief Executive Officer and PresidentDavid E. Lancaster . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $240,000Executive Vice President, Chief Operating Officer and ChiefFinancial OfficerMatthew V. Hairford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $240,000Executive Vice President — OperationsBradley M. Robinson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $200,000Vice President — Reservoir Engineering

Although Mr. Nicklin is retained officially as an independent contractor, he serves as our ExecutiveDirector of Exploration and is included and treated as a Named Executive Officer for the purposes of thisprospectus. Mr. Nicklin retired in 2000 as the Chief Geologist for ARCO and desires to maintain a measureof independence and flexibility in his schedule. Under this independent contractor arrangement, we are ableto obtain the benefit of his experience and expertise that we would otherwise not have. Based on therecommendations of Mr. Foran and Mr. Laney, the board of directors (other than Mr. Foran) and thePlanning and Compensation Committee decided that for most of 2011, Mr. Nicklin’s base rate wouldremain at $1,500 per day.

Mr. Robinson’s base salary was increased effective January 1, 2011 to $225,000. Originally, basedupon the review of the base salaries paid by the 2011 compensation peer companies and consultation withMr. Foran (other than with regard to his base salary), the Planning and Compensation Committee and theboard of directors (other than Mr. Foran) determined that the base salaries for the Named Executive Officersother than Mr. Robinson and Mr. Massad (who was not an executive officer at such time) were to beincreased to the following amounts upon the completion of this offering:

• Mr. Foran — $550,000

• Mr. Lancaster — $340,000

• Mr. Hairford — $275,000

• Mr. Nicklin — $2,000 per day of which $250 per day will be deferred until the end of the threeyear independent contractor agreement; provided Mr. Nicklin’s engagement continues until thatpoint. Payments will actually be made to his consulting company.

However, due to the timing of this offering, the Nominating, Compensation and Planning Committeeand the Independent Directors determined to make the increases set forth above effective for Messrs.Lancaster, Hairford and Nicklin on December 1, 2011, and for Mr. Foran effective January 1, 2012.Mr. Foran’s increased base salary was set between the 25th-50th percentiles of base compensation levels ofthe peer companies. The increased base salaries for all other Named Executive Officers were set in therange of the 25th percentile of the peer companies for positions indicated above.

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Mr. Massad was an independent contractor for us from September 2010 until November 30, 2011 andwas paid $7,500 per month for such services with it being anticipated that he would provide suchindependent contractor services for one to two days per week. On December 1, 2011, we hired him as ourExecutive Vice President – Capital Markets with a base salary of $225,000 which was recommended by Mr.Foran and approved by the Nomination, Compensation and Planning Committee and the IndependentDirectors.

2011 Cash Bonuses

Although we had originally planned to adopt an Annual Incentive Plan for 2011 and to make the 2011incentive payments based on the Annual Incentive Plan, due to the timing of this offering, the board ofdirectors decided to adopt the Annual Incentive Plan effective January 1, 2012 and to make our incentivepayments for 2012 performance under the Annual Incentive Plan as described below under “2012 AnnualIncentive Compensation.”

For the 2011 cash bonuses, a sub-committee of the Nominating, Compensation and PlanningCommittee and the Independent Directors is planning to make recommendations regarding such bonuses forthe Named Executive Officers to the Nominating, Compensation and Planning Committee and theIndependent Directors in February 2012, and then the Nominating, Compensation and Planning Committeeand the Independent Directors are planning to determine the amounts of the cash bonuses to be paid to theNamed Executive Officers. Although there are not any formulaic plans for determining the 2011 cashbonuses, the Nominating, Compensation and Planning Committee and the Independent Directors anticipatethat the rationale for the cash bonus to be paid to each Named Executive Officer will be based on both thecompany-wide 2011 performance and the applicable Named Executive Officer’s individual 2011contribution as determined by the Nominating, Compensation and Planning Committee and the IndependentDirectors.

In addition, to reward Messrs. Foran, Lancaster and Hairford for their valuable contributions in thepreparation of this offering, the Planning and Compensation Committee (a predecessor committee to theNominating, Compensation and Planning Committee) authorized a bonus payment to them of $50,000,$40,000 and $20,000, respectively. In 2011, the Nominating, Compensation and Planning Committee andthe Independent Directors ratified such bonus payments.

Pursuant to the terms of Mr. Nicklin’s independent contractor agreement, if the board of directorsdetermines that he has fulfilled his duties in a reasonably satisfactory manner, his consulting company willbe paid a bonus of at least $50,000 for 2011.

Mr. Massad received a $100,000 sign-on bonus pursuant to the terms of his employment agreementdue to the fact that he had provided independent contractor services for significantly more than one to twodays per week and had been traveling more than anticipated when he originally agreed to the independentcontractor arrangement.

2011 Long-Term Incentive Compensation

Although the Nominating, Compensation and Planning Committee and the Independent Directors hadoriginally planned to make equity grants to the Named Executive Officers in 2011 consisting of non-qualified stock options, performance shares and time-lapsed restricted shares, the Nominating,Compensation and Planning Committee and the Independent Directors decided not to make any equitygrants to Named Executive Officers in 2011 due to the timing of this offering.

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Benefits

We offer a variety of health and welfare programs to all eligible employees, including the executiveofficers other than Mr. Nicklin. The health and welfare programs are intended to protect employees againstcatastrophic loss and encourage a healthy lifestyle. Our health and welfare programs include medical,pharmacy, dental, disability and life insurance. We also have a 401(k) plan for all full time employees,including the executive officers, other than Mr. Nicklin, in which we contribute 3% of the employee’s basesalary and have the discretion to match dollar-for-dollar up to an additional 4% of the employee’s electivedeferral contributions. We generally do not offer perquisites to our executives, including our NamedExecutive Officers. However, we guaranteed the repayment of loans to certain of our Named ExecutiveOfficers by Comerica Bank. These guaranties were terminated in January 2012 (See “Certain Relationshipsand Related Party Transactions — Loan Program”).

How We Determine Each Element of 2012 Compensation

2012 Base Salary

For 2012, after receiving input from Mr. Foran, the Nominating, Compensation and PlanningCommittee and the Independent Directors decided to leave the salaries for Messrs. Foran, Lancaster,Massad and Nicklin at the amounts set forth above after giving effect to the increase in Mr. Foran’s basesalary to $550,000 beginning on January 1, 2012. With regard to Messrs. Hairford and Robinson, afterreceiving input from Mr. Foran, the Nominating, Compensation and Planning Committee and theIndependent Directors decided to increase the base salaries effective January 1, 2012 for Mr. Hairford to$300,000 and for Mr. Robinson to $240,000. Mr. Hairford’s raise was based upon his role in completing ourEagle Ford acreage acquisition in DeWitt, Karnes, Wilson and Gonzales counties and for his leadership ininitiating our ongoing drilling and completion operations in the Eagle Ford shale. Mr. Robinson’s raise wasbased upon his ongoing leadership in coordinating our non-operating participation interests in theHaynesville shale and elsewhere and for his specific technical contributions to our completion operations inthe Eagle Ford shale and our exploration efforts in the Meade Peak shale.

2012 Annual Incentive Compensation

Effective January 1, 2012, we adopted an Annual Incentive Plan. All awards made pursuant to theAnnual Incentive Plan will be cash awards. Such awards will be paid to the Named Executive Officers assoon as practical following completion of the plan year and, in any case, within the first 135 days followingthe end of the plan year.

Each year, the Nominating, Compensation and Planning Committee will recommend to theIndependent Directors and the Independent Directors will set annual performance criteria for the NamedExecutive Officers based on the possible performance criteria that are set forth in the Annual Incentive Plan.Such criteria may include financial, operational and strategic performance goals for the company, companyperformance measures and company performance relative to peers. The Nominating, Compensation andPlanning Committee will also recommend to the Independent Directors and the Independent Directors willset corresponding performance payment amounts based on the achievement of such performance criteria byeach Named Executive Officer.

In addition to the annual performance criteria, in order to give the Nominating, Compensation andPlanning Committee and the Independent Directors flexibility, the Nominating, Compensation and PlanningCommittee may make recommendations to the Independent Directors and the Independent Directors maydecide after completion of our fiscal year to decrease the amount of the payments relating to the

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corresponding performance criteria or to increase the amount of the payments to the Named ExecutiveOfficers. Any increase may be in response to unforeseen circumstances when the performance criteria wereset. Any such increase may or may not be based on the list of performance criteria set forth in the AnnualIncentive Plan and may be made irrespective of whether any payments are made regarding the performancecriteria.

For 2012, we plan to utilize performance criteria which may include, without limitation, such items asproduction volumes, oil and natural gas reserves added, EBITDA, finding costs and lease operatingexpenses as well as environmental compliance measures and safety and accident rates. In February 2012,we anticipate that a sub-committee of the Nominating, Compensation and Planning Committee andIndependent Directors (the Nominating, Compensation and Planning Committee and the IndependentDirectors are currently comprised of the same members) will recommend to the Nominating, Compensationand Planning Committee and the Independent Directors and the Nominating, Compensation and PlanningCommittee and the Independent Directors will determine the threshold, target and maximum performancemeasures for the selected performance criteria, the weighting of such criteria in comparison to the otherperformance criteria and the corresponding annual incentive opportunity expressed as a percentage of basesalary for each Named Executive Officer for the threshold, target and maximum performance criteria levels.In future years, we may add more quantitative performance criteria to the measurement in order to bettermeasure Named Executive Officer contributions to our performance.

The threshold opportunity will be aligned with the performance goals established for each NamedExecutive Officer, such that meeting the threshold level of all performance criteria may result in the NamedExecutive Officer earning his threshold annual incentive opportunity set forth under the performancecriteria. The target opportunity will be aligned with the performance goals established for each NamedExecutive Officer, such that meeting the target level for all of the performance criteria may result in theNamed Executive Officer earning his target annual incentive opportunity set forth under the performancecriteria. The maximum opportunity will be aligned with the performance goals established for each NamedExecutive Officer, such that meeting the maximum level of all performance criteria may result in theNamed Executive Officer earning his maximum annual incentive opportunity set forth under theperformance criteria. The table which follows sets forth the anticipated threshold, target and maximumincentive opportunities for the Named Executive Officers for 2012 based on the to be selected performancecriteria.

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Participant

ThresholdAnnual IncentiveOpportunity as

% of 2012Base Salary

Target AnnualIncentive Opportunity

as % of 2012Base Salary

Maximum AnnualIncentive Opportunity

as % of 2012Base Salary

Joseph Wm. Foran . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37.5% 75% 150%Chairman of the Board, Chief Executive Officer and President

David E. Lancaster . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32.5% 65% 130%Executive Vice President, Chief Operating Officer and ChiefFinancial Officer

Matthew V. Hairford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32.5% 65% 130%Executive Vice President — Operations

Wade I. Massad . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32.5% 65% 130%Executive Vice President — Capital Markets

David F. Nicklin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25% 50%(1) 100%Executive Director of Exploration

Bradley M. Robinson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25% 50% 100%Vice President — Reservoir Engineering

(1) The target annual incentive opportunity, expressed in dollars, assumes that Mr. Nicklin works 210 days per year at the rate of $2,000 perday. Payments will actually be made to his consulting company.

In early 2013, with regard to each Named Executive Officer, after taking into account the performancecriteria and all other information with regard to such Named Executive Officer, the Nominating,Compensation and Planning Committee (or sub-committee thereof) may recommend to the IndependentDirectors that any Named Executive Officer be paid an annual award and the Independent Directors willdetermine the annual award to be paid to such Named Executive Officer, if any. The amount of such annualaward may be greater than or less than the payment opportunity based on the performance criteria so long asthe annual award does not exceed 200% of the applicable Named Executive Officer’s annual base salary.

Pursuant to the terms of his employment agreement, Mr. Massad will receive a $150,000 bonus uponcompletion of this offering due to his experience in the capital markets arena which has assisted thecompany in both amending and restating our senior secured revolving credit agreement and arranging forunderwriters on acceptable terms for this offering.

Long-Term Incentive Plan

Effective January 1, 2012, the board of directors adopted the 2012 Long-Term Incentive Plan. Thisplan permits the granting of long-term equity and cash incentive awards, including the following:

• stock options;

• stock appreciation rights;

• restricted stock (time-lapse and performance-based);

• restricted stock units (both time-lapse and performance-based);

• performance shares;

• performance units;

• stock grants; and

• performance cash awards.

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The board of directors has determined not to make any additional grants of awards under the 2003Plan, and the 2012 Long-Term Incentive Plan will replace the 2003 Plan going forward. The 2012 Long-Term Incentive Plan has 4,000,000 shares of common stock or share equivalents reserved for issuance. Theplan covers grants to the Named Executive Officers, key employees, consultants and non-employeedirectors.

After receiving recommendations from the Nominating, Compensation and Planning Committee (or asub-committee thereof), the plan will be administered by the Independent Directors, who will authorize andapprove grants, including the size and terms of such grants such as vesting and the lapsing of restrictions.For 2012, the Independent Directors anticipate that the Named Executive Officers will receive non-qualifiedstock options, performance shares and time-lapsed restricted shares with each type of grant for each NamedExecutive Officer having a present value equal to one-third of the value of all long-term incentivecompensation awarded during 2012 to such Named Executive Officer. Mr. Nicklin’s grants will be made tohis consulting company.

The stock options will be granted at 100% of fair market value of our common stock on the date ofgrant and will vest equally on the first four anniversaries of the grant date if the Named Executive Officer isstill employed by us on such dates. The Independent Directors anticipate that the performance shares will besubject to a three-year performance period following the date of grant, and the number of performanceshares earned by each participant may range from 0% to 200% of the shares granted subject to performancecriteria if the Named Executive Officer is still employed by us at the end of the three-year performanceperiod or an independent contractor with us with regard to Mr. Nicklin. The Independent Directors expectthe performance criteria will be our total shareholder return relative to the peer companies set forth above asmeasured by the increase in share price over the three-year performance period plus the value of dividends(reinvested in an equivalent value of shares at the end of the month if and when any dividends are declared).The Independent Directors believe if our total shareholder return is equal to the 50th percentile of the totalshareholder return of the peer companies, then the Named Executive Officer will earn 100% of the sharesgranted. The Independent Directors believe if our total shareholder return is equal to the 75th percentile ofthe peer companies, the Named Executive Officer will earn 150% of the performance shares granted. TheIndependent Directors believe if our total shareholder return is equal to 90% or greater of the peercompanies, the Named Executive Officer will receive 200% of the performance shares granted. TheIndependent Directors believe if our total shareholder return is below the 35th percentile of the peercompanies, the Named Executive Officer will not earn any of the performance shares granted. TheIndependent Directors expect the number of shares earned between the 35th percentile and the50th percentile, the 50th percentile and the 75th percentile and the 75th percentile and the 90th percentile willbe on a straight line interpolation basis. The Independent Directors anticipate the restrictions on thetime-lapsed restricted shares will lapse equally on the first three anniversaries of the grant date if the NamedExecutive Officer is still employed with us on such dates. During the restricted period, the NamedExecutive Officer will be eligible to receive dividends on and vote the restricted shares.

Pursuant to the terms of his employment agreement, Mr. Massad is to receive a grant of stock optionsexercisable into 150,000 shares of our common stock if the offering price is determined by June 1, 2012 atan exercise price equal to the greater of $12 per share or the per share offering price of this offering. If theoffering price of this offering is not determined by June 1, 2012, Mr. Massad will be granted the stockoptions on June 1, 2012 at an exercise price equal to the greater of $12 per share or the fair market value ofa share of our common stock on June 1, 2012. The stock options are to vest in three equal installments oneach of December 1, 2012, 2013 and 2014 if Mr. Massad is still employed by us on such dates.

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How Elements of Our Compensation Program Are Related to Each Other

We view the various components of compensation as related but distinct with generally a significantportion of total compensation reflecting “pay for performance.” We do not have any formal or informalpolicies or guidelines for allocating compensation between long-term and currently paid out compensationor between cash or non-cash compensation.

Accounting and Tax Considerations

Under Section 162(m) of the Code, a limitation is placed on tax deductions of any publicly-heldcorporation for individual compensation to certain executives of such corporation exceeding $1.0 million inany taxable year, unless the compensation is performance based. Since we have not been a publicly-heldcompany, Section 162(m) has not applied to us, and there is an exception to this deductibility limitation fora specified period of time in the case of companies such as us that become publicly-held.

Termination of Employment Arrangements and Independent Contractor Agreement

Employment Agreements and Independent Contractor Agreement

For 2010 and until August 8, 2011, all of the Named Executive Officers other than Messrs. Foran,Massad and Nicklin were parties to employment agreements which provided for “at will” employment witheither party being required to provide two weeks advanced notice of termination of employment. Theseemployment agreements did not provide for any additional payments upon termination by either party, evenafter a change in control, other than accrued and unused vacation. For 2010 and until August 8, 2011,Mr. Nicklin was party to an independent contractor agreement which provided for either party beingrequired to provide fifteen days advance notice of termination. This independent contractor agreement didnot provide for any additional payments upon termination by either party, even after a change in control,other than for services performed prior to the date of termination.

As described under “Discussion Regarding Summary Compensation Table and Grants of Plan-BasedAwards Table,” in contemplation of this offering, on August 9, 2011, we entered into employmentagreements with Messrs. Foran, Lancaster, Hairford and Robinson and an independent contractor agreementwith Mr. Nicklin and his consulting company, and on December 1, 2011 we entered into an employmentagreement with Mr. Massad.

Under the employment agreements, if one of the following occurs:

• the Named Executive Officer dies;

• the Named Executive Officer is totally disabled;

• we mutually agree to end the employment agreement;

• we dissolve and liquidate; or

• the term of the employment agreement ends,

we will pay the Named Executive Officer the average of his annual bonus for the prior two years pro-ratedbased on the number of complete or partial months completed during the year of termination.

Also, under the employment agreements, if one of the following occurs:

• the Named Executive Officer is terminated other than (i) as set forth above, (ii) by us for just cause,or (iii) in connection with a “change in control” as described below; or

• the Named Executive Officer terminates his employment for “good reason,”

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if the Named Executive Officer is Mr. Foran, we will pay him twice his base salary and twice the average ofhis annual bonus for the prior two years; if the Named Executive Officer is Messrs. Lancaster, Hairford orMassad we will pay him 1.5 times his base salary and 1.5 times the average of his annual bonus for the priortwo years; and if the Named Executive Officer is Mr. Robinson, we will pay him one year of base salaryand the average of his annual bonus for the prior two years.

Finally, under the employment agreements, upon a “change in control” and within 30 days prior to the“change in control” or within 12 months after the “change in control,” if we terminate a Named ExecutiveOfficer without just cause or the Named Executive Officer terminates his employment with or without“good reason,” if the Named Executive Officer is Messrs. Foran, Lancaster, Hairford or Massad, we willpay him three times his base salary and three times the average of his annual bonus for the prior two years;and if the Named Executive Officer is Mr. Robinson, we will pay him twice his base salary and twice theaverage of his annual bonus for the prior two years. Until Mr. Massad has been employed for two completecalendar years, Mr. Massad’s bonus for any calendar year for which he does not have a bonus history, otherthan bonuses specifically contemplated by his employment agreement, will be deemed to be the same as thebonuses paid to our Executive Vice President—Operations for such year.

“Change in control” is defined under Section 409A of the Code as follows:

• A change in ownership of the company occurs on the date that, except in certain situations, resultsin someone acquiring more than 50% of the total fair market value or voting power of thecompany’s stock;

• A change in effective control of the company occurs on one of the following dates:

• The date that a person acquires (or has acquired in a 12 month period) ownership of 30% ormore of the company’s total voting power; however, if a person already owns at least 30% ofthe company’s total voting power, the acquisition of additional control does not constitute achange in control; or

• The date during a 12 month period where a majority of the company’s board of directors isreplaced by directors whose appointment or election was not endorsed by a majority of theboard of directors; and

• A change in the ownership of a substantial portion of the company’s assets occurs on the date aperson acquires (or has acquired in a 12 month period) assets of the company having a total grossmarket value of at least 40% of the total gross fair market value of all of the company’s assetsimmediately before such acquisition.

For purposes of the employment agreements, “good reason” means:

• The assignment of duties inconsistent with the title of the Named Executive Officer or his currentoffice or a material diminution of the Named Executive Officer’s current authority, duties orresponsibilities;

• A diminution of the Named Executive Officer’s base salary or a material breach of the employmentagreement; or

• Other than with respect to Mr. Massad, the relocation of the company’s principal executive officesmore than 30 miles from the company’s present principal executive offices or the transfer of theNamed Executive Officer to a place other than the company’s principal executive offices; and

• The action causing the “good reason” is not cured within the applicable cure period.

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For purposes of the employment agreements, “just cause” means:

• The Named Executive Officer’s continued and material failure to perform the duties of hisemployment consistent with his position other than due to disability;

• The Named Executive Officer’s failure to perform his material obligations under the employmentagreement other than due to disability;

• The Named Executive Officer’s material breach of the company’s written policies concerningdiscrimination, harassment or securities trading;

• The Named Executive Officer’s refusal or failure to follow lawful directives of the board ofdirectors and any supervisors other than due to disability;

• The Named Executive Officer’s commission of fraud, theft or embezzlement;

• The Named Executive Officer’s conviction or indictment of a felony or other crime involvingmoral turpitude; or

• The Named Executive Officer’s intentional breach of fiduciary duty; and

• The action causing the “just cause” is not cured within the applicable cure period.

Under Mr. Nicklin’s independent contractor agreement, if one of the following occurs:

• he dies;

• he is totally disabled;

• we mutually agree to end the independent contractor agreement;

• we dissolve and liquidate; or

• the term of the independent contractor agreement ends,

we must pay his consulting company (i) the average of the annual bonus paid to the consulting company forthe prior two years pro-rated based on the number of complete or partial months completed during the yearof termination and (ii) all accrued and vested compensation under our incentive plans. In addition, ifMr. Nicklin dies or is totally disabled during the three year term of the independent contractor agreement,his consulting company will be paid $250 per day that Mr. Nicklin consulted for us during the term of theindependent contractor agreement.

Also, under the independent contractor agreement, if one of the following occurs:

• the independent contractor agreement is terminated by us for a reason other than as set forth aboveor in connection with a “change in control” as described below; or

• he terminates the independent contractor agreement for “good reason” (as described in connectionwith the employment agreements set forth above),

we must pay an amount equal to $1,000 per full business day for the lesser of (i) the time Mr. Nicklinconsulted for us during the prior twelve months of the term of the independent contractor agreement or(ii) the time between August 9, 2011 and the date the independent contractor agreement was terminated plusaccrued and vested compensation under our equity plans.

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Finally, under the independent contractor agreement, upon a “change in control” (as described inconnection with the employment agreements set forth above) and within 30 days prior to the “change incontrol” or within 12 months after the “change in control,” if we terminate Mr. Nicklin without “just cause”(as described in connection with the employment agreements set forth above) or Mr. Nicklin terminates hisindependent contractor agreement with or without “good reason,” we will pay an amount equal to two timesthe aggregate amount paid based on the daily rate during the prior twelve months plus accrued and vestedcompensation under our equity plans.

Equity Plans

The 2003 Plan provides that all awards automatically vest upon a “change in control.”

See the definition of “change in control” under “— Potential Payments upon Termination or Change inControl.”

The “change in control” provisions in the employment agreements, the independent contractoragreement and the 2003 Plan help prevent management from being distracted by rumored or actual changesin control. The “change in control” provisions provide:

• incentives for the Named Executive Officers to remain with us despite the uncertainties of apotential or actual change in control;

• assurance of severance payments for terminated Named Executive Officers; and

• access to equity compensation after a change in control.

We believe a single trigger is appropriate for the following reasons:

• to be competitive with what we believe to be the standards for payments upon a “change incontrol”;

• with regard to equity, employees or independent contractors who remain after a “change in control”are treated the same as the general shareholders who could sell or otherwise transfer their equityupon a “change in control”; and

• since we would not exist in our present form after a “change in control,” Named Executive Officersshould not have to have their compensation dependent on the new company.

Stock Ownership Guidelines

We have adopted stock ownership guidelines for our executive officers that cover the followingexecutive officers and designated amounts:

• Chairman, President and Chief Executive Officer — shares equal to five times base salary;

• Executive Vice Presidents — shares equal to two and 1⁄2 times base salary; and

• Vice Presidents and Executive Directors — shares equal to one and 1⁄2 times base salary.

Each of the foregoing executive officers has five years from the date of the closing of this offering inwhich to achieve the stock ownership position. Shares which will count toward the stock ownershipguidelines include time-lapse restricted shares that are still restricted and any shares held in trust by theexecutive officer or his immediate family over which he has direct beneficial ownership interest. Shareswhich will not count toward the stock ownership guidelines include shares underlying unexercised stockoptions, unexercised stock appreciation rights and performance-based awards for which the performancerequirements have not been satisfied.

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Summary Compensation Table

The following table summarizes the total compensation awarded to, earned by or paid to Messrs.Foran, Lancaster, Hairford, Nicklin and Robinson for 2010 and 2011, and for Mr. Massad for 2011 since hewas not an executive officer in 2010. This table and the accompanying narrative should be read inconjunction with the Compensation Discussion and Analysis, which sets forth the objectives and otherinformation regarding our executive compensation program.

Name and Principal Position YearSalary

($)Bonus

($)

OptionAwards(1)

($)

All OtherCompensation

($)Total

($)

Joseph Wm. Foran . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 $240,000 $ 50,000(2) – $18,019(3) $308,019Chairman of the Board, Chief Executive Officer and President 2010 $240,000 $400,000 – $17,994(4) $657,994

David E. Lancaster . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 $248,333 $ 40,000(2) – $17,150(5) $305,483Executive Vice President, Chief Operating Officer and 2010 $240,000 $100,000 $46,781 $17,150(5) $403,931Chief Financial Officer

Matthew V. Hairford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 $242,917 $ 20,000(2) – $17,150(5) $280,067Executive Vice President — Operations 2010 $240,000 $150,000 $31,187 $17,150(5) $438,337

Wade I. Massad . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 $101,250(6) $100,000(2) – $ 8,313(7) $209,563Executive Vice President — Capital Markets

David F. Nicklin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 $320,750(8) $ 50,000(9) – – $370,750Executive Director of Exploration 2010 $315,000(10) $ 35,000 $32,556 – $382,556

Bradley M. Robinson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 $225,000 –(2) – $15,831(11) $240.831Vice President — Reservoir Engineering 2010 $200,000 $ 50,000 $15,594 $17,150(5) $282,744

(1) Option awards are the grant date fair values computed in accordance with FASB ASC Topic 718. Our policy and assumptions made inthe valuation of the stock options are contained in Note 2 and Note 8 of the audited financial statements for the year ended December 31,2010.

(2) Reflects bonuses paid in 2011. See “Compensation Discussion and Analysis – 2011 Cash Bonuses” regarding the potential for furtherbonuses to be paid in 2012 regarding 2011 performance.

(3) Consists of $17,150 in 401(k) matching contributions as described in “– Benefits” and $869 in premiums reimbursed to Mr. Foran for adisability policy covering Mr. Foran.

(4) Consists of $17,150 in 401(k) matching contributions as described in “– Benefits” and $844 in premiums reimbursed to Mr. Foran for adisability policy covering Mr. Foran.

(5) Consists of $17,150 in 401(k) matching contributions as described in “– Benefits.”

(6) Consists of independent contractor payments from January 1, 2011 through November 30, 2011 and salary for December 2011.


(8) Based on the aggregate amount of payments made to Mr. Nicklin under his independent contractor agreement as determined by his baserate of $1,500 per day from January 1, 2011 through November 30, 2011 and $1,750 per day for December 2011.

(9) Pursuant to his independent contractor agreement, Mr. Nicklin’s consulting company will be paid at least $50,000 for 2011 if the boardof directors determines that he fulfilled his duties in a reasonably satisfactory manner. The board of directors has not met on this issue asof January 16, 2012. Therefore, $50,000 has been included at this time, but the exact amount to be awarded to Mr. Nicklin is not known.

(10) Based on the aggregate amount of payments made to Mr. Nicklin as determined by his base rate of $1,500 per day under his independentcontractor agreement.


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Discussion Regarding Summary Compensation Table and Grants of Plan-Based Awards Table

For 2010 and until August 8, 2011, all of our Named Executive Officers, other than Messrs. Foran,Massad and Nicklin, were parties to employment agreements with the company that were similar in termswith the exception of certain benefits such as salaries. Under these agreements, the employment was “atwill.” Either party could terminate the employee’s employment with or without cause at any time upon thegiving of two weeks notice. There were no guaranteed payments of any kind for any of our NamedExecutive Officers, including Mr. Foran, in the event of a change of control. These agreements required theemployee to maintain the confidentiality of our trade secrets, technical data, customer lists, trainingmanuals, financial reports and other confidential information and knowledge regarding our business. Theemployee was required to deliver any property in his possession or control that is our property upontermination of employment.

For 2010 and until August 8, 2011, Mr. Nicklin was party to an independent contractor agreement withthe company. Under this independent contractor agreement, Mr. Nicklin’s services were subject totermination upon the giving of 15 days notice by either party. There were no guaranteed payments of anykind to Mr. Nicklin, other than reimbursement for services rendered and associated expenses through thedate of termination. This agreement required Mr. Nicklin to maintain the confidentiality of our trade secrets,technical data, customer lists, training manuals, financial reports and other confidential information andknowledge regarding our business. Mr. Nicklin was required to deliver any property in his possession orcontrol that is our property upon termination of his independent contractor agreement.

On August 9, 2011, we entered into employment agreements with Messrs. Foran, Lancaster, Hairfordand Robinson and an independent contractor agreement with Mr. Nicklin.

Mr. Foran. His employment agreement is for a twenty-four month term and such term automaticallyextends each month by one additional month unless either the company or Mr. Foran gives written noticethat the term will no longer be extended. For 2011, his base salary was $240,000. Effective January 1, 2012,the base salary is $550,000, and he is eligible to participate in our annual incentive plan and our long-termincentive plan. See “Compensation Discussion and Analysis — Termination of Employment Arrangementsand Independent Contractor Agreement — Employment Agreements and Independent ContractorAgreement” regarding the payments to be made to Mr. Foran upon termination of his employment and/or a“change in control.”

Mr. Lancaster. His employment agreement is for an eighteen month term and such term automaticallyextends each month by one additional month unless either the company or Mr. Lancaster gives writtennotice that the term will no longer be extended. From January 1, 2011 through November 30, 2011, his basesalary was $240,000. Effective October 1, 2011, the base salary is $340,000, and he is eligible to participatein our annual incentive plan and our long-term incentive plan. See “Compensation Discussion and Analysis— Termination of Employment Arrangements and Independent Contractor Agreement — EmploymentAgreements and Independent Contractor Agreement” regarding the payments to be made to Mr. Lancasterupon termination of his employment and/or a “change in control.”

Mr. Hairford. His employment agreement is for an eighteen month term and such term automaticallyextends each month by one additional month unless either the company or Mr. Hairford gives written noticethat the term will no longer be extended. From January 1, 2011 through November 30, 2011, his base salarywas $240,000. From December 1, 2011 through December 31, 2011, the base salary was $275,000.Effective January 1, 2012, his base salary was $300,000 and he is eligible to participate in our annual

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incentive plan and our long-term incentive plan. See “Compensation Discussion and Analysis —Termination of Employment Arrangements and Independent Contractor Agreement — EmploymentAgreements and Independent Contractor Agreement” regarding the payments to be made to Mr. Hairfordupon termination of his employment and/or a “change in control.”

Mr. Robinson. His employment agreement is for a twelve month term and such term automaticallyextends each month by one additional month unless either the company or Mr. Robinson gives writtennotice that the term will no longer be extended. From January 1, 2011 through November 30, 2011, the basesalary was $225,000. Effective December 1, 2011, the base salary was $240,000, and he is eligible toparticipate in our annual incentive plan and our long-term incentive plan. See “Compensation Discussionand Analysis — Termination of Employment Arrangements and Independent Contractor Agreement —Employment Agreements and Independent Contractor Agreement” regarding the payments to be made toMr. Robinson upon termination of his employment and/or a “change in control.”

Mr. Nicklin. His independent contractor agreement is for a thirty-six month term. From January 1,2011 through November 30, 2011, the daily rate was $1,500 per day. Effective December 1, 2011, the dailyrate is $1,750 per day that Mr. Nicklin consults for us, and if the independent contractor agreement remainsin effect until the end of the thirty-six month term, we will pay an additional $250 per day that Mr. Nicklinconsulted for us during the thirty-six months. Mr. Nicklin, through his consulting company, is eligible toparticipate in our annual incentive plan and our long-term incentive plan. Also, for 2011, if the board ofdirectors determines that Mr. Nicklin has fulfilled his duties in a reasonably satisfactory manner, hisconsulting company will be paid a bonus of at least $50,000. See “Compensation Discussion and Analysis— Termination of Employment Arrangements and Independent Contractor Agreement — EmploymentAgreements and Independent Contractor Agreement” regarding the payments to be made to Mr. Nicklin’sconsulting company upon termination of the independent contractor agreement and/or a “change in control.”

Mr. Massad. His employment agreement is for a twelve month term and such term will automaticallybe extended for six additional months unless either the company or Mr. Massad gives 60 days written noticeprior to the end of the initial twelve months that the term will not be extended at the end of the initial twelvemonths. The base salary is $225,000, and he is eligible to participate in our annual incentive plan and ourlong-term incentive plan. He received a sign-on bonus of $100,000. See “Compensation Discussion andAnalysis — How We Determine Each Element of 2012 Compensation — 2012 Annual IncentiveCompensation” regarding the bonus to be paid to Mr. Massad upon completion of this offering, and see“Compensation Discussion and Analysis — How We Determine Each Element of 2012 Compensation —Long-Term Incentive Plan” regarding the stock options to be granted to Mr. Massad in 2012. See“Compensation Discussion and Analysis — Termination of Employment Arrangements and IndependentContractor Agreement — Employment Agreements and Independent Contractor Agreement” regarding thepayments to be made to Mr. Massad upon termination of his employment and/or a “change in control.”

Bonuses. See “Compensation Discussion and Analysis — How We Determined Each Element of 2011Compensation — 2011 Cash Bonuses” regarding the cash bonuses that we paid to the Named ExecutiveOfficers other than Mr. Robinson for 2011 through January 16, 2012 and the rationale for such payments.

General. Base salary paid and the amount of cash bonuses paid in 2011 represented from 93.4% to100% of the Named Executive Officers’ total compensation as represented in the Summary CompensationTable with the percentages being as follows: Mr. Foran — 94.2%; Mr. Lancaster — 94.4%; Mr. Hairford —93.9%; Mr. Massad — 96.0%; Mr. Nicklin — 100%; and Mr. Robinson — 93.4%.

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Outstanding Equity Awards at December 31, 2011

The following table summarizes the total outstanding equity awards at December 31, 2011 for eachNamed Executive Officer:

Option Awards

Number ofSecurities

UnderlyingUnexercised

StockOptions

(#)

Number ofSecurities

UnderlyingUnexercised

StockOptions

(#)

OptionExercise

PriceOption

ExpirationName Exercisable Unexercisable ($) Date

Joseph W. Foran . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – – –David E. Lancaster . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60,000 – $ 9.00 2/7/12

56,250 18,750 $10.00 2/12/133,750 11,250 $ 9.00 2/21/20

Matthew V. Hairford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30,000 – $ 9.00 2/7/1267,500 22,500 $10.00 2/12/132,500 7,500 $ 9.00 2/21/20

Wade I. Massad . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – – –David F. Nicklin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,000 – $10.00 2/12/13

2,500 7,500 $ 9.00 2/21/20Bradley M. Robinson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,000 – $ 9.00 2/7/12

22,500 7,500 $10.00 2/12/131,250 3,750 $ 9.00 2/21/20

The following table provides the vesting dates at December 31, 2011 for unvested stock options:

Vesting DateJoseph Wm.

ForanDavid E.

LancasterMatthew V.

HairfordWade I.Massad

David F.Nicklin

Bradley M.Robinson

2/13/12 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 18,750 22,500 – – 7,5002/22/12 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 3,750 2,500 – 2,500 1,2502/22/13 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 3,750 2,500 – 2,500 1,2502/22/14 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 3,750 2,500 – 2,500 1,250

Total Unvested Stock Options . . . . . . . . . . . . . . . . . . . . . – 30,000 30,000 – 7,500 11,250

Option Exercises and Stock Vested During 2011

The following table summarizes, for the Named Executive Officers in 2011, the number of sharesacquired upon exercise of stock options and the value realized, each before payout of any applicablewithholding tax:

Option Awards

Name

Number ofShares

Acquired onExercise

(#)

ValueRealized on

Exercise($)(1)

Dateof

Exercise

Joseph Wm. Foran . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – –David E. Lancaster . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – –Matthew V. Hairford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30,000 60,000 6/29/11Wade I. Massad . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – –David F. Nicklin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – –Bradley M. Robinson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – –

(1) Determined based on the difference between the $9.00 exercise price of the stock options and the fair market value of our Class Acommon stock on the date of exercise which was $11.00 per share on June 29, 2011.

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Potential Payments Upon Termination or Change in Control

Under the 2003 Plan, all awards vest upon a change in control. Assuming there was a change in controlon December 31, 2011, the Named Executive Officers would have received the following amounts inautomatic vesting of stock options based on an assumed fair market value of $15.00 on December 31, 2011:Mr. Foran — $0; Mr. Lancaster — $161,250; Mr. Hairford — $157,000; Mr. Massad — $0; Mr. Nicklin —$45,000; and Mr. Robinson — 60,000. A “change in control” occurs upon any of the following events:

• any person (or group of persons acting in concert), other than the company or an affiliate, becomesthe beneficial owner, directly or indirectly, of voting securities representing 30% or more of thevoting power of our then outstanding voting securities (with the threshold percentage beingincreased, not to exceed 50% for the beneficial owners of our voting securities for whomWellington Management Company, LLP serves as an investment advisor if those owners aredeemed to be a “group” for this purpose);

• our board of directors ceases to consist of a majority of continuing directors; where “continuingdirector” means a member of the board who was either (i) a member of the board at October 31,2008 or (ii) nominated, appointed or approved, following nomination by our shareholders, to serveas a director by a majority of the then continuing directors;

• our shareholders approve (i) any consolidation or merger with us or any subsidiary that results inthe shareholders immediately prior to the consolidation or merger holding less than a majorityownership interest in the outstanding voting securities of the surviving entity, (ii) any sale, lease,exchange or other transfer of all or substantially all of our assets or (iii) any plan or proposal forour liquidation or dissolution; or

• our shareholders accept a share exchange in which our shareholders immediately before such shareexchange do not hold, immediately following such share exchange, the total voting securities of thesurviving entity in substantially the same proportion as held before the share exchange.

Employment Agreements and Independent Contractor Agreement

As described under “Discussion Regarding Summary Compensation Table and Grants of Plan-BasedAwards Table,” in contemplation of this offering, on August 9, 2011, we entered into employmentagreements with Messrs. Foran, Lancaster, Hairford and Robinson and an independent contractor agreementwith Mr. Nicklin and his consulting company, and on December 1, 2011, we entered into an employmentagreement with Mr. Massad. Pursuant to the terms of the employment agreements and independentcontractor agreement, we may be required to make certain payments to one or more of our NamedExecutive Officers upon the occurrence of certain events resulting in such Named Executive Officer’stermination. For a detailed description of the events that may trigger such payments, see “CompensationDiscussion and Analysis — Termination of Employment Arrangements and Independent ContractorAgreement — Employment Agreements and Independent Contractor Agreement.”

The employment agreements and the independent contractor agreement each contain a non-disclosureof confidential information provision that requires each Named Executive Officer to maintain, both duringand after employment, the confidentiality of information used by such Named Executive Officer in theperformance of his job duties.

Additionally, each of the employment agreements contain a non-competition provision, pursuant towhich Messrs Foran, Lancaster, Hairford, Massad and Robinson have agreed that: (i) for six monthsfollowing termination by us for total disability, or by such Named Executive Officer for good reason, or(ii) for 12 months following termination (a) by us for just cause, (b) by such Named Executive Officer other

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than for good reason, or (c) in connection with a change in control, such Named Executive Officer shall not,without our prior written consent (not to be unreasonably withheld if the Named Executive Officer’semployment is terminated other than for good reason), directly or indirectly: (x) invest in (other thaninvestments in publicly-owned companies which constitute not more than 1% of the voting securities of anysuch company) a competing business with significant assets in the restricted area (each as defined below),or (y) participate in a competing business as a manager, employee, director, officer, consultant, independentcontractor, or other capacity or otherwise provide, directly or indirectly, services or assistance to acompeting business in a position that involves input into or direction of such competing business’s decisionswithin the restricted area.

Similarly, Mr. Nicklin’s independent contractor agreement contains a non-competition provisionpursuant to which Mr. Nicklin has agreed that following termination: (i) by us for total disability or justcause, (ii) by Mr. Nicklin for good reason or other than for good reason, or (iii) in connection with a changein control, then for a period of 12 months thereafter, Mr. Nicklin may not, without our prior written consent,directly or indirectly (x) invest in (other than investments in publicly-owned companies which constitute notmore than 5% of the voting securities of any such company) a competing business with significant assets inthe restricted area, or (y) participate in a competing business as a manager, employee, director, officer,consultant, independent contractor, or other capacity or otherwise provide, directly or indirectly, services orassistance to a competing business in a position that involves input into or direction of the competingbusiness’s decisions within the restricted area.

For purposes of the employment agreements and independent contractor agreement:

“competing business” means any person or entity engaged in oil and natural gas exploration,development, production and acquisition activities.

“significant assets” means oil and natural gas reserves with an aggregate fair market value of $25million or more.

“restricted area” means a one-mile radius of any oil and natural gas reserves held by us as of the end ofemployee’s employment, plus any county or parish where we have significant assets as of the end ofemployee’s employment. However, for purposes of Mr. Nicklin’s independent contractor agreement,restricted area means a one-mile radius of any oil and natural gas reserves held by us as of the end of theperformance of his independent contractor services, plus any county or parish where we have significantassets as of the end of the performance of his independent contractor services other than a one-mile radiusof any oil and natural gas reserves held by Salt Creek Petroleum as of August 9, 2011 to the extentpreviously disclosed to us and any new oil and natural gas reserves that may be approved by us afterAugust 9, 2011.

See the definitions of “change in control,” “good reason” and “just cause” set forth in“— Compensation Discussion and Analysis — Termination of Employment Arrangements and IndependentContractor Agreement — Employment Agreements and Independent Contractor Agreement.”

Furthermore, other than Mr. Foran’s employment agreement, each employment agreement and theindependent contractor agreement contains an anti-solicitation provision, pursuant to which, during therestricted periods described above, subject to certain exceptions, Messrs Lancaster, Hairford, Massad,Nicklin and Robinson shall not, without our prior written consent, solicit for employment or a contractingrelationship, or employ or retain any person who is or has been, within six months prior to such time,employed by or engaged as an individual independent contractor by us or our affiliates or induce or attemptto induce any such person to leave his or her employment or independent contractor relationship with us orour affiliates.

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For the Named Executive Officer to receive any severance payments described below for terminationby us without just cause, by the Named Executive Officer for good reason or, following a change in control,by us without cause or by the Named Executive Officer with or without good reason, the Named ExecutiveOfficer must comply with the non-disclosure, non-competition and non-solicitation provisions describedabove.

Finally, as a condition to receiving any severance payments and other payments under their respectiveemployment agreements or independent contractor agreement, as applicable, each Named Executive Officeris required to execute a separation agreement and release in favor of us.

To describe the payments and benefits that are triggered for each event of termination, we have createdthe following table estimating the payments and benefits that would be paid to each Named ExecutiveOfficer under each element of our compensation program assuming that such Named Executive Officer’semployment agreement or independent contractor agreement, as applicable, terminated on December 31,2011, the last day of our 2011 fiscal year. In all cases, the amounts were valued as of December 31, 2011,based upon, where applicable, an estimated fair value of our common stock of $15.00. The amounts in thefollowing table are calculated as of December 31, 2011 pursuant to Securities and Exchange Commissionrules and are not intended to reflect actual payments that may be made. Actual payments that may be madewill be based on the dates and circumstances of the applicable event.

Payment Upon Termination

Named Executive OfficerCategory of

Payment

Upon Death orTotal

Disability(1)

Upon MutualAgreement orDissolution/

Liquidation(1)

Termination by UsWithout Just Cause

or by NamedExecutive Officer

for Good Reason(1)

Termination Followinga Change in ControlWithout Cause or by

Named ExecutiveOfficer With or Without

Good Reason(11)

Joseph Wm. Foran . . . . . . . . . . . Salary $ – $ – $480,000(5) $ 720,000(12)

Bonus $225,000(2) $225,000(2) $450,000(6) $ 675,000(13)

Vesting options $ – $ – $ – $ –

Total: $225,000 $225,000 $930,000 $1,395,000

David E. Lancaster . . . . . . . . . . . Salary $ – $ – $510,000(7) $1,020,000(12)

Bonus $ 70,000(2) $ 70,000(2) $105,000(8) $ 210,000(13)

Vesting options $ – $ – $ – $ 161,250(14)

Total: $ 70,000 $ 70,000 $615,000 $1,391,250

Matthew V. Hairford . . . . . . . . . Salary $ – $ – $412,500(7) $ 825,000(12)

Bonus $ 85,000(2) $ 85,000(2) $127,500(8) $ 255,000(13)

Vesting options $ – $ – $ – $ 157,000(14)

Total: $ 85,000 $ 85,000 $540,000 $1,237,000

Wade I. Massad . . . . . . . . . . . . . Salary $ – $ – $450,000(7) $ 675,000(12)

Bonus $125,000(2),(3) $125,000(2),(3) $187,500(8) $ 375,000(3),(13)

Vesting options $ – $ – $ – $ –

Total: $125,000 $125,000 $637,501 $1,050,000

David F. Nicklin . . . . . . . . . . . . . Salary $ 21,625(4) $ – $ 86,500(9) $ 134,000(15)

Bonus $ 42,500(2) $ 42,500(2) $ – $ –Vesting options $ – $ – $ – $ 45,000(14)

Total: $ 64,125 $ 42,500 $ 86,500 $ 179,000

Bradley M. Robinson . . . . . . . . . Salary $ – $ – $225,000(10) $ 450,000(5)

Bonus $ 25,000(2) $ 25,000(2) $ 25,000(2) $ 50,000(6)

Vesting options $ – $ – $ – $ 60,000(14)

Total: $ 25,000 $ 25,000 $250,000 $ 560,000

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(1) Amounts due upon death, total disability, mutual agreement, dissolution or liquidation, termination by us without cause or termination byNamed Executive Officer for good reason are payable in lump sum on the sixtieth day following the date of termination unless otherwiserequired by Section 409A of the Code.

(2) Represents the average annual amount of bonuses paid to such Named Executive Officer with respect to prior two calendar years (2010-2011).

(3) Since Mr. Massad has not been employed for two complete calendar years, Mr. Massad’s bonus for 2010 is deemed to be the same as thebonuses paid to Mr. Hairford for 2010.

(4) Consists of cash payment of $250 for each full business day worked by Mr. Nicklin during the term of the independent contractoragreement.

(5) Represents two times such Named Executive Officer’s base salary as of the termination date.

(6) Represents two times an amount equal to the average annual amount of bonuses paid to such Named Executive Officer with respect toprior two calendar years.

(7) Represents 1.5 times such Named Executive Officer’s base salary as of the termination date.

(8) Represents 1.5 times an amount equal to the average annual amount of bonuses paid to such Named Executive Officer with respect toprior two calendar years.

(9) Consists of a cash payment of $1,000 for each full business day worked by Mr. Nicklin during the term of his independent contractoragreement.

(10) Represents such Named Executive Officer’s base salary as of the termination date.

(11) Amounts due following a change in control are payable in lump sum on the date which immediately follows six months from the date oftermination or, if earlier, within 30 days of such Named Executive Officer’s death.

(12) Represents three times such Named Executive Officer’s base salary as of the termination date.

(13) Represents three times an amount equal to the average annual amount of bonuses paid to such Named Executive Officer with respect toprior two calendar years.

(14) The employment agreements and independent contract agreement provide for accelerated and full vesting of unvested incentive awardsheld by a Named Executive Officer in the event that such Named Executive Officer is terminated within 30 days prior to, or 12 monthsfollowing, a “change in control.” The amount disclosed reflects the difference between an assumed fair value of our common stock atDecember 31, 2011 of $15.00 and the exercise price of the unvested options that would vest upon a change in control.

(15) Consists of a cash payment consisting of two times the aggregate of: (i) $1,500 for each full-business day worked on and between Augustand November, 2011, inclusive, and (ii) $1,750 for each full business day worked during December 2011.

2011 Director Compensation

NameFees Earned or

Paid in Cash Stock Awards(1)(2)All Other

Compensation Total

$ $ $ $Charles L. Gummer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,917 6,000 – 13,917Stephen A. Holditch . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,000 21,250 – 41,250David M. Laney . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,167 27,250 – 46,417Gregory E. Mitchell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,917 21,500 – 34,417Steven W. Ohnimus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,167 27,000 – 46,167Michael C. Ryan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,000 21,500 – 41,500Edward R. Scott, Jr.(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,000 11,250 – 26,250Margaret B. Shannon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,917 24,250 – 37,167

(1) Based on the fair market value of the stock awards on the date of grant.

(2) The following directors own the following number of fully vested options to purchase common stock at December 31, 2011: Stephen A.Holditch (10,500), David M. Laney (6,750), Steven W. Ohnimus (14,250) and Michael C. Ryan (1,500).

(3) Retired from board of directors on June 6, 2011.

Prior to November 1, 2011, each non-employee director was paid $1,250 each month in cash for a totalannual stipend of $15,000. Effective November 1, 2011 each non-employee director is entitled to an annualcash retainer of $40,000. Each non-employee director currently receives 250 shares of Class A commonstock for each day of attendance at each board meeting or committee meeting, other than telephonic

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meetings. In addition, we reimburse our directors for travel, lodging and related expenses incurred inattending board and committee meetings. Non-employee directors do not receive any other remuneration fortheir service as directors. Some directors have performed consulting services for the company and havereceived grants of stock options or shares as remuneration for these services.

Upon consummation of this offering, we will target our non-employee directors’ compensation at the25th percentile of the peer companies used for benchmarking the non-employee directors’ compensation.Upon consummation of this offering, our director compensation program will be as follows:

• Annual cash retainer of $40,000;

• Cash meeting fee of $1,000 per day for each day of board and committee service;

• The chairs of the Audit Committee and Engineering Committee will each receive an additional cashretainer of $5,000 annually; and

• Each non-employee director will receive restricted stock units (“RSUs”) equal to up to $75,000 invalue with the restrictions lapsing in one-third increments on each of the first, second and thirdanniversaries of the date of grant. Each grant may be adjusted downward (but not upward) in valueproportionate to the non-employee director’s attendance at any board or committee meetings calledduring the period for which RSUs are due.

Each non-employee director may elect to defer his or her RSUs until the director is no longer on theboard due to normal retirement, resignation, death, disability, failure to be re-nominated to the board orfailure to be re-elected by shareholders to the board. When the restrictions lapse, each RSU will give thedirector a share of common stock.

Upon the completion of this offering, we anticipate that the non-employee directors will follow ourvoluntary stock ownership guidelines for non-employee directors. Within three years of becoming adirector, each non-employee director will be expected to own $250,000 of the company’s common stockand continue to hold such shares while serving as a director. With the exception of Mr. Gummer who joinedthe board of directors in September 2011, all directors presently meet this standard. Shares which will counttoward the stock ownership guidelines include time-lapse restricted shares or RSUs that are still restrictedand any shares held in trust by the director or his immediate family over which he has direct beneficialownership interest. Shares which will not count toward the stock ownership guidelines include sharesunderlying unexercised stock options and unexercised stock appreciation rights.

Special Board Advisor Compensation

Other than Mr. Downey, each special board advisor is paid $1,250 each month in cash for a totalannual stipend of $15,000. In addition, other than Mr. Downey, each special board advisor is granted 250shares of Class A common stock for each day of attendance at each board meeting or committee meeting,other than telephonic meetings. In addition, we reimburse our special board advisors for travel, lodging andrelated expenses incurred in attending board and committee meetings. Other than Mr. Downey, specialboard advisors do not receive any other remuneration for their service as special board advisors. Except forMr. Downey, upon the completion of this offering, we anticipate that the compensation of the special boardadvisors will remain at its current levels. Mr. Downey currently receives the same compensation as our non-employee directors and upon consummation of this offering, his compensation will be modified in the samemanner as for the non-employee directors as described above.

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Securities Authorized for Issuance Under Equity Compensation Plans

The following table presents the securities authorized for issuance under our equity compensationplans as of December 31, 2011.

Equity Compensation Plan Information

Plan Category

Number ofShares to beIssued UponExercise of

OutstandingOptions,

Warrantsand

Rights

Weighted-AverageExercisePrice of

OutstandingOptions,

Warrantsand Rights

($)

Number ofShares

RemainingAvailable for

FutureIssuance

Under EquityCompensation

Plans

Equity compensation plans approved by security holders(1) . . . . . . . . 1,024,500 $9.75 –Equity compensation plans not approved by security holders(2) . . . . . – – 4,000,000

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,024,500 $9.75 4,000,000

(1) Our board of directors has determined not to make any additional awards under the 2003 Plan.(2) Our 2012 Long-Term Incentive Plan was approved by our board of directors in December 2011 and took effect on January 1, 2012.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Since January 1, 2009, there has not been, nor is there currently proposed, any transaction or series ofsimilar transactions to which we were or are a party in which the amount involved exceeded or exceeds$120,000 and in which any of our directors, executive officers, holders of more than 5% of any class of ourvoting securities or any member of the immediate family of any of the foregoing persons, had or will have adirect or indirect material interest, other than compensation arrangements with directors and executiveofficers, which are described in “Compensation of Named Executive Officers,” and the transactionsdescribed or referred to below.

Participation in Our Initial Public Offering

The following directors and executive officers have indicated to us that they currently intend topurchase the following amounts of common stock in the directed share program in this offering at the initialprice to the public:

Director or Executive Officer Amount

Joseph Wm. Foran(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,000,000Wade I. Massad(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 250,000David M. Laney(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 600,000Charles L. Gummer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 330,000Margaret B. Shannon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200,000Gregory E. Mitchell(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200,000

(1) $1,500,000 of shares are expected to be purchased by Mr. Foran and $500,000 of shares are expected to be purchased by SageResources, Ltd., a limited partnership owned by the Foran family, including Mr. Foran.

(2) Shares may be purchased by Mr. Massad or an entity over which Mr. Massad has investment and voting authority.

(3) $300,000 of shares are expected to be purchased by Laney Investments Ltd.

(4) Shares are expected to be purchased by JAMAL Enterprises, LP, for which Mr. Mitchell has sole voting and investment authority.

These prospective purchasers have the right to purchase these shares, but are under no obligation topurchase any shares in this offering and their interest in purchasing shares in this offering is not acommitment to do so. The underwriters will receive the same discount from shares of our common stockpurchased by such directors and officers as they will from other shares of our common stock sold to thepublic in this offering. Any shares purchased by such directors and officers will be subject to lock-uprestrictions described in the section entitled “Underwriters.”

Loan Program

We guaranteed the repayment of loans to certain of our executive officers by Comerica Bank. Thepurpose of these loans was to assist our executive officers in buying shares of our common stock pursuantto the exercise of stock options. We guaranteed the repayment of loans and made deposits of funds incertificates of deposit to secure our guaranties for the following executive officers:

Executive Officer and Date of Loan or Renewal Loan Amount Interest Rate

Interest Paidor Payable in

2011Maturity

Date

Matthew V. Hairford; December 29, 2009; renewedOctober 8, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . $310,000 5.25% $16,231 April 5, 2012

David E. Lancaster; April 30, 2009; renewedMay 30, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . $470,000 5.25% $24,608 May 29, 2012

Bradley M. Robinson; December 29, 2008; renewedJanuary 29, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . $280,000 5.25% $14,660 January 28, 2012

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Our board of directors approved the termination of the loan program on April 7, 2011 and weterminated our guaranties and the associated pledge of our certificates of deposit with Comerica Bankrelating to these loans in January 2012.

Repurchase of Our Securities

In November 2010, we repurchased 20,000 shares of Class A common stock from Bradley M.Robinson for a total of $220,000; we repurchased 25,000 shares of Class A common stock from Matthew V.Hairford for a total of $275,000; and we repurchased 30,000 shares of Class A common stock from DavidE. Lancaster for a total of $330,000.

In April 2010, we repurchased 1,000,000 shares of Class A common stock from five shareholders, alladvised by Wellington Management Company, LLP, for a total of $9,000,000. The purchase price for suchshares of Class A common stock was determined through negotiations with Wellington ManagementCompany, LLP.

In September 2009, we repurchased 52,500 shares of Class A common stock from Scott E. King for atotal of $390,000.

In April 2009, we repurchased from one of our shareholders, Gandhara Master Fund Limited,5,422,713 shares of Class A common stock for a total of $27,113,565. The purchase price for such shares ofClass A common stock was determined through negotiations with Gandhara Master Fund Limited.

Issuance of Our Securities

In January 2011 we completed a private placement offering of shares of our Class A common stock.See “Business — Recent Developments.” As detailed in the table below, several of our directors andexecutive officers participated in such offering on the same terms and conditions as the other investors inthe offering.

Director or Executive Officer Aggregate Consideration

Joseph Wm. Foran . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,171,500(1)

David M. Laney . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 473,000(2)

Michael C. Ryan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,100,000Margaret Shannon(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 249,700

(1) Sage Resources, Ltd., which is a limited partnership owned by the Foran family, including Mr. Foran, purchased a portion of the sharesfor an aggregate consideration of $346,500.

(2) Mr. Laney’s adult children purchased a portion of the shares for an aggregate consideration of $198,000. Mr. Laney has the power tovote his children’s shares pursuant to a revocable power of attorney. In addition, Laney Investments Ltd. purchased a portion of theshares for an aggregate consideration of $275,000.

(3) Mrs. Shannon was not a member of our board of directors at the time of purchase.

In May 2009 through September 2009, we sold, in a private placement offering, shares of our Class Acommon stock to our existing shareholders. As detailed in the table below, several of our directors andexecutive officers participated in such offering on the same terms and conditions as the other investors inthe offering.

Director or Executive Officer Aggregate Consideration

Joseph Wm. Foran . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,370,860(1)

David E. Lancaster . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 123,750(2)

David M. Laney . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 859,550(3)

Michael C. Ryan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 169,038

(1) Sage Resources, Ltd., which is a limited partnership owned by the Foran family, including Mr. Foran, and two of Mr. Foran’s minorchildren purchased a portion of the shares for an aggregate consideration of $596,000.

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(2) Mr. Lancaster’s Individual Retirement Account purchased all of the shares.

(3) Mr. Laney’s adult children purchased a portion of the shares for an aggregate consideration of $146,250. Mr. Laney has the power tovote his children’s shares pursuant to a revocable power of attorney. In addition, Laney Investments Ltd. purchased a portion of theshares for an aggregate consideration of $515,730.

Corporate Reorganization

In connection with our corporate reorganization, we engaged in certain transactions with certainaffiliates and our existing equity holders. Please see “Corporate Reorganization” for a description of thesetransactions.

Other Transactions

In January 2007, we agreed with one of our shareholders, Roxanna Oil, Inc., to obtain acreage and tomarket a new natural gas prospect in the Meade Peak shale in southwest Wyoming and adjacent areas inUtah and Idaho. The principals of Roxanna Oil are Marlan W. Downey and his daughter, Julie DowneyGarvin. Mr. Downey is an officer, director and shareholder of Roxanna Oil and is a special advisor to ourboard of directors and one of our shareholders. Ms. Garvin is President of Roxanna Oil and the formerChief Geophysicist for Marathon Oil Corporation. Our subsidiary, MRC Rockies Company, has obtainedapproximately 146,000 gross and 139,000 net acres in the prospect at a cost of approximately $9.3 millionat December 31, 2010. Mr. Downey and Ms. Garvin assisted with the marketing of the prospect to industrypartners for joint development.

In May 2010, Roxanna Rocky Mountains, LLC (a wholly owned subsidiary of Roxanna Oil) andAlliance Capital Real Estate, Inc. entered into a participation agreement with our subsidiary, MRC RockiesCompany, to explore and develop our Meade Peak prospect. For more information concerning theagreement with Alliance Capital Real Estate, please see the discussion under “Business — Other SignificantPrior Events — Alliance Capital Participation Agreement.”

Procedures for Approval of Related Party Transactions

Our board of directors has adopted a written related party transaction policy. Pursuant to this policy, a“Related Party Transaction” is defined as a transaction (including any financial transaction, arrangement orrelationship (including any indebtedness or guarantee of indebtedness)), or series of related transactions, orany material amendment to any such transaction, involving a Related Party (as defined below) and in whichwe are a participant, other than:

• a transaction involving compensation of directors;

• a transaction involving compensation of an executive officer or involving an employmentagreement, severance agreement, change in control provision or agreement or a specialsupplemental benefit for an executive officer;

• a transaction available to all employees generally or to all salaried employees generally;

• a transaction with a Related Party involving less than $120,000;

• a transaction in which the interest of the Related Party arises solely from the ownership of a classof our equity securities and all holders of that class receive the same benefit on a pro rata basis; or

• a transaction in which the rates or charges involved therein are determined on competitive bids, ora transaction that involves the rendering of services as a common or contract carrier, or publicutility, at rates or charges fixed in conformity with law or governmental authority.

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“Related Party” means:

• any person who is, or at any time during the applicable period was, one of our executive officers orone of our directors or nominees for directors;

• any person who is known by us to be the beneficial owner of more than 5.0% of our commonstock;

• any immediate family member of any of the foregoing persons, which means any child, stepchild,parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law,brother-in-law or sister-in-law of a director, nominee for director, executive officer or a beneficialowner of more than 5.0% of our common stock; and

• any firm, corporation or other entity that is owned or controlled by any of the foregoing persons orin which any of the foregoing persons is a general partner or executive officer or in which suchperson, together with all other of the foregoing persons, has a 10.0% or greater beneficialownership interest.

Pursuant to our related party transaction policy, the Audit Committee must review all material facts ofeach Related Party Transaction and recommend either approval or disapproval of the Related PartyTransaction to the full board of directors, subject to certain limited exceptions. In determining whether torecommend approval or disapproval of the Related Party Transaction, the Audit Committee must, afterreviewing all material facts of the Related Party Transaction and the Related Party’s relationship andinterest, determine whether the Related Party Transaction is fair to the company. Further, the policy requiresthat all Related Party Transactions be disclosed in our filings with the SEC and/or our website in accordancewith applicable laws, rules and regulations. All of the Related Party Transactions discussed above occurredprior to the adoption of the policy.

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CORPORATE REORGANIZATION

Overview

We were recently incorporated pursuant to the laws of the State of Texas as Matador Holdco, Inc. tobecome a holding company for Matador Resources Company, a Texas corporation. Matador ResourcesCompany was formed as a Texas corporation in July 2003. Pursuant to the terms of the corporatereorganization that was completed on August 9, 2011 (as described below) former Matador ResourcesCompany, now known as MRC Energy Company, became a wholly owned subsidiary of current MatadorResources Company, formerly known as Matador Holdco, Inc. In connection with the reorganization,former Matador Resources Company changed its corporate name to MRC Energy Company and MatadorHoldco, Inc. changed its corporate name to Matador Resources Company.

Merger

To accommodate growth through acquisitions, provide potential protection from liability and facilitatefuture sales or spinoffs of subsidiaries and holding company financing arrangements, the former MatadorResources Company, now known as MRC Energy Company, determined it was in the best interests of thecorporation and its shareholders that the company reorganize into a holding company structure pursuant toSection 10.005 of the Texas Business Organizations Code. In accordance with Section 10.005, we created awholly owned subsidiary, Matador Holdco, Inc., now known as Matador Resources Company, solely for thepurposes of creating a holding company structure. Matador Holdco, Inc. created a wholly owned subsidiary,Matador Merger Co., a Texas corporation, solely to be a constituent party to the holding company merger.Pursuant to Section 10.005, Matador Merger Co. merged with Matador Resources Company, now known asMRC Energy Company. Matador Resources Company, now known as MRC Energy Company, was thesurviving party of the merger and as a result of the merger, became a wholly owned subsidiary of MatadorHoldco, Inc., now known as Matador Resources Company. The former Matador Resources Companychanged its name to MRC Energy Company, and the former Matador Holdco, Inc. changed its name toMatador Resources Company.

Because we accomplished the holding company merger in accordance with Section 10.005 of theTexas Business Organizations Code, approval by the shareholders of the former Matador ResourcesCompany, now known as MRC Energy Company, was not required. In addition, as a result of the merger,the shareholders of the former Matador Resources Company, now known as MRC Energy Company,received shares of Matador Holdco, Inc., now known as Matador Resources Company, in exchange for theshares of the former Matador Resources Company, now known as MRC Energy Company, then held bysuch shareholders, and the shareholders of the former Matador Resources Company had no appraisal rights.

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Immediately prior to the corporate reorganization, the corporate structure of the three aforementionedentities was as follows:

Matador Resources Company

Matador Holdco, Inc.

Matador Merger Co.

Immediately after the corporate reorganization, the corporate structure of the aforementioned entities isas follows:

Matador Resources Company(formerly known as Matador Holdco, Inc.)

MRC Energy Company(formerly known as Matador Resources

Company)

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PRINCIPAL AND SELLING SHAREHOLDERS

The following table sets forth information with respect to the beneficial ownership of our common stock atJanuary 27, 2012 by:

• each person who we know owns beneficially approximately 5% or more of our common stock;

• each of our directors;

• each of our executive officers;

• all of our executive officers and directors as a group; and

• each selling shareholder.

Except as otherwise indicated, the persons or entities listed below have sole voting and investment powerwith respect to all shares of our common stock beneficially owned by them, except to the extent this power may beshared with a spouse. All information with respect to beneficial ownership has been furnished by the respectivedirectors, officers, persons beneficially owning 5% or more of our common stock and selling shareholders, as thecase may be. Except as otherwise indicated, each of the selling shareholders has represented to us that it is not abroker-dealer or an affiliate of a broker-dealer and the address for each beneficial owner is 5400 LBJ Freeway,Suite 1500, Dallas, Texas 75240.

Beneficial Owner or Selling Shareholder

Beneficial Ownership(1)

of Class A Common StockPrior to this Offering

BeneficialOwnership(1)

of Class BCommon Stock

Numberof

Shares tobe Sold in

theOffering(3)


of CommonStock After

this Offering(2)

MaximumNumber ofAdditional

Shares to beSold Upon

Full Exerciseof

Underwriters’Option(4)

BeneficialOwnership(1) ofCommon Stock

After Exercise ofUnderwriters’

Option in Full(2)

Number(2)Percent of

Class(2) NumberPercent of

Class(2) Number(3)Percent of


Class(4)

Joseph Wm. Foran(5) . . . . . . . . . . . . 3,628,313 8.4% 880,700 85.4% — 3,628,313 6.6% — 3,628,313 6.5%Wellington Management Company,

LLP(6)

280 Congress StreetBoston, Massachusetts 02210 . . . 7,355,003 17.1% — — — 6,160,113 11.3% — 5,072,041 9.2%

Spindrift Partners, L.P.(7)

c/o Wellington ManagementCompany, LLP280 Congress StreetBoston, Massachusetts 02210 . . . 3,010,600 7.0% — — 488,992 2,521,608 4.6% 445,233 2,076,375 3.7%

Spindrift Investors (Bermuda) L.P.(8)

c/o Wellington ManagementCompany, LLP280 Congress StreetBoston, Massachusetts 02210 . . . 3,301,200 7.7% — — 536,398 2,764,802 5.1% 488,439 2,276,363 4.1%

General Mills, Inc. Benefit FinanceCommittee(9)

Number One General MillsBlvd.Minneapolis, Minnesota55426 . . . . . . . . . . . . . . . . . . . . . . 4,563,685 10.6% — — — 4,563,685 8.3% — 4,563,685 8.2%

Charles L. Gummer . . . . . . . . . . . . . 500 * — — — 500 * — 500 *Stephen A. Holditch(10) . . . . . . . . . . 126,253 * — — — 126,253 * — 126,253 *David M. Laney(11) . . . . . . . . . . . . . 654,977 1.5% — — — 654,977 1.2% — 654,977 1.2%Steven W. Ohnimus(12) . . . . . . . . . . 97,777 * — — — 97,777 * — 97,777 *Michael C. Ryan(13) . . . . . . . . . . . . . 250,320 * — — — 250,320 * — 250,320 *Margaret B. Shannon . . . . . . . . . . . 24,575 * — — — 24,575 * — 24,575 *Gregory E. Mitchell(14) . . . . . . . . . . 174,625 * — — — 174,625 * — 174,625 *Scott E. King(15) . . . . . . . . . . . . . . . . 970,500 2.3% 150,000 14.6% — 970,500 1.8% — 970,500 1.8%Bradley M. Robinson(17) . . . . . . . . . 248,500 * — — 15,000(16) 233,500 * — 233,500 *David E. Lancaster(18) . . . . . . . . . . . 377,250 * — — 60,000(16) 317,250 * — 317,250 *Matthew V. Hairford(19) . . . . . . . . . 257,800 * — — 25,000(16) 232,800 * — 232,800 *Wade Massad(20) . . . . . . . . . . . . . . . 74,675 * — — — 74,675 * — 74,675 *David F. Nicklin(21) . . . . . . . . . . . . . 50,000 * — — — 50,000 * — 50,000 *Executive officers and directors as a

group(22) . . . . . . . . . . . . . . . . . . . . 6,936,065 16.0% — — 100,000 6,836,065 12.4% — 6,836,065 12.3%

173

Beneficial Owner orSelling Shareholder

Beneficial Ownership(1)

of Class A Common StockPrior to this Offering


of Class BCommon Stock

Numberof

Shares tobe Sold in

theOffering(3)


of CommonStock After

this Offering(2)

MaximumNumber ofAdditional

Shares to beSold Upon

Full Exerciseof

Underwriters’Option(4)

BeneficialOwnership(1) ofCommon Stock

After Exercise ofUnderwriters’

Option in Full(2)

Number(2)Percent of

Class(2) NumberPercent of



Class(4)

Other Selling ShareholdersAllan Burns . . . . . . . . . . . . . . . . . . . . 117,000 * — — 8,759 108,241 * 8,241 100,000 *Arthur L. Smith . . . . . . . . . . . . . . . . 100,000 * — — 5,152 94,848 * 4,848 90,000 *Baylor University(23) . . . . . . . . . . . . . 600,000 1.4% — — 112,153 487,847 * 103,833 384,014 *BlackRock Asset Allocation

Portfolio of BlackRockFunds(24) . . . . . . . . . . . . . . . . . . . . 8,685 * — — 4,510 4,175 * 4,175 — *

RBC Wealth Management IRA CustFBO C.A. Rundell, Jr.(25) . . . . . . . 129,375 * — — 13,331 116,044 * 12,544 103,500 *

Coterie Capital Partners, Ltd.(26) . . . . 20,700 * — — 10,749 9,951 * 9,951 — *Daniel Beaulne . . . . . . . . . . . . . . . . . 34,500 * — — 6,448 28,052 * 5,970 22,082 *Greg L. McMichael(27) . . . . . . . . . . . 47,355 * — — 2,883 44,472 * 2,712 41,760 *Jack A. Turpin . . . . . . . . . . . . . . . . . 7,800 * — — 1,458 6,342 * 1,350 4,992 *C. Taylor Yoakam(28) . . . . . . . . . . . . 9,750 * — — 1,868 7,882 * 1,757 6,125 *Joni Yoakam(28) . . . . . . . . . . . . . . . . . 9,750 * — — 1,868 7,882 * 1,757 6,125 *LFC Energy Resources, Ltd.(29) . . . . 121,682 * — — 22,743 98,939 * 21,056 77,883 *Michael Money Adams(30) . . . . . . . . 35,525 * — — 2,576 32,949 * 2,424 30,525 *Global Natural Resources III(31) . . . . 594,200 1.4% — — 96,538 497,662 * 87,900 409,762 *Placer Creek Investors

(Bermuda) L.P.(32). . . . . . . . . . . . . 211,300 * — — 34,347 176,953 * 31,300 145,653 *Placer Creek Partners, L. P.(33) . . . . . 237,703 * — — 38,615 199,088 * 35,200 163,888 *Sherree G. Funk(34) . . . . . . . . . . . . . . 149,750 * — — 2,243 147,507 * 2,076 145,431 *Swank Investment

Partnership LP(35) . . . . . . . . . . . . . 32,745 * — — 6,120 26,625 * 5,666 20,959 *Swank MLP Convergence

Fund LP(35) . . . . . . . . . . . . . . . . . . 133,200 * — — 24,895 108,305 * 23,049 85,256 *Thomas R. Helfand . . . . . . . . . . . . . . 5,502 * — — 561 4,941 * 519 4,422 *Indranil Barman(36) . . . . . . . . . . . . . . 161,635 * — — 21,000(16) 140,635 * — 140,635 *Amanda M. Crawford(37) . . . . . . . . . 42,300 * — — 3,700(16) 38,600 * — 38,600 *Maria E. Diaz(38) . . . . . . . . . . . . . . . . 11,445 * — — 3,000(16) 8,445 * — 8,445 *Michael G. Ernest(39) . . . . . . . . . . . . . 100,700 * — — 9,000(16) 91,700 * — 91,700 *B. J. Frazier(40) . . . . . . . . . . . . . . . . . 23,150 * — — 3,800(16) 19,350 * — 19,350 *Floyd H. Henk, Jr.(41) . . . . . . . . . . . . 65,000 * — — 15,000(16) 50,000 * — 50,000 *Yvonne Hoevers(42) . . . . . . . . . . . . . . 28,750 * — — 5,000(16) 23,750 * — 23,750 *James A. Juett(43) . . . . . . . . . . . . . . . . 91,995 * — — 12,000(16) 79,995 * — 79,995 *Ryan London(44) . . . . . . . . . . . . . . . . 78,400 * — — 15,000(16) 63,400 * — 63,400 *Ava L. Monroe(45) . . . . . . . . . . . . . . . 15,445 * — — 6,000(16) 9,445 * — 9,445 *Janie L. Nelson(46) . . . . . . . . . . . . . . . 31,250 * — — 6,000(16) 25,250 * — 25,250 *DeBorah Paine(47) . . . . . . . . . . . . . . . 6,000 * — — 3,000(16) 3,000 * — 3,000 *Diane Scott(48) . . . . . . . . . . . . . . . . . . 28,110 * — — 3,000(16) 25,110 * — 25,110 *Mitzi Scott(49) . . . . . . . . . . . . . . . . . . 7,100 * — — 3,000(16) 4,100 * — 4,100 *Steve W. Sinclair(50) . . . . . . . . . . . . . 66,150 * — — 15,000(16) 51,150 * — 51,150 *Winifred A. Suarez(51) . . . . . . . . . . . . 5,000 * — — 3,000(16) 2,000 * — 2,000 *Margie Waters-Hudson(52) . . . . . . . . 11,500 * — — 2,460(16) 9,040 * — 9,040 *Kathy Wayne(53) . . . . . . . . . . . . . . . . 57,525 * — — 14,500(16) 43,025 * — 43,025 *

* Less than 1.0%.

(1) Under applicable rules promulgated by the SEC pursuant to the Exchange Act, a person is deemed the “beneficial owner” of a security withregard to which the person, directly or indirectly, has or shares (a) the voting power, which includes the power to vote or direct the voting of thesecurity, or (b) the investment power, which includes the power to dispose or direct the disposition of the security, in each case irrespective ofthe person’s economic interest in the security. Under these SEC rules, a person is deemed to beneficially own securities which the person has theright to acquire within 60 days through (x) the exercise of any option or warrant or (y) the conversion of another security.

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(2) Percentages based on a total of 42,022,493 shares of Class A common stock issued and outstanding prior to this offering, which includes285,000 shares of Class A common stock to be issued to certain holders of stock options prior to consummation of this offering inconnection with the exercise of their stock options, 243,460 of which shares will be sold by certain of the option holders as sellingshareholders in this offering and 1,030,700 shares of Class B common stock issued and outstanding prior to this offering. All shares ofClass B common stock will automatically convert on a one-for-one basis into shares of Class A common stock upon the consummationof this offering pursuant to the terms of our certificate of formation. Therefore, the Class A common stock amounts include the Class Bcommon stock amounts based on the one-for-one conversion. See “Description of Capital Stock” for details regarding the automaticconversion of the Class B common stock upon the consummation of this offering.

(3) Gives effect to the issuance and sale by us of 11,666,667 shares in the offering and the sale by the selling shareholders of the number ofshares of common stock indicated. Excludes any shares that may be purchased in the directed share program.

(4) If the underwriters fully exercise their option to purchase additional shares, then we will issue 700,000 additional shares and the sellingshareholders will sell the number of shares of common stock indicated. Excludes any shares that may be purchased in the directed shareprogram.

(5) Includes (i) 250,000 shares of Class B common stock and 756,533 shares of Class A common stock held of record by Sage Resources,Ltd., which is a limited partnership owned by the Foran family, including Mr. Foran; (ii) an aggregate of 19,000 shares held of record bytwo of Mr. Foran’s college age children; (iii) 135,500 shares and 50,000 shares of common stock held of record by The Don ForanFamily Trust 2008 and The Foran Family Special Needs Trust, respectively, for which Mr. Foran is the co-trustee and over whichMr. Foran has shared voting and investment power with other members of his family; and (iv) 893,290 shares of Class A common stockand 315,350 shares of Class B common stock held of record by the JWF 2011-1 GRAT and 893,290 shares of Class A common stockand 315,350 shares of Class B common stock held of record by the NNF 2011-1 GRAT, for which Mr. Foran is the trustee and overwhich Mr. Foran has sole voting and investment power. The column for Class A common stock includes 880,700 shares of Class Acommon stock issuable upon the automatic conversion of the shares of Class B common stock held by Sage Resources, Ltd., the JWF2011-1 GRAT and the NNF 2011-1 GRAT at the consummation of this offering.

(6) Wellington Management Company, LLP (“Wellington Management”) has an indirect interest in 7,355,003 shares held of record bySpindrift Partners, L.P., Spindrift Investors (Bermuda), L.P., Global Natural Resources III, Placer Creek Investors Bermuda L.P. andPlacer Creek Partners L.P. Wellington Management is an investment adviser registered under the Investment Advisers Act of 1940, asamended. Wellington Management, in such capacity, may be deemed to share beneficial ownership over the shares held by its clientaccounts. See footnotes 7, 8, 33, 34 and 35 regarding Wellington Management’s client accounts’ affiliations with one or more broker-dealers and material relationships with us within the past three years.

(7) Wellington Management, as investment adviser to Spindrift Partners, L.P., may be deemed to have shared voting and dispositive powerover the shares held by Spindrift Partners, L.P. Spindrift Partners, L.P. is affiliated with one or more registered broker-dealers. SpindriftPartners, L.P. purchased the shares being registered hereunder in the ordinary course of business and, at the time of purchase, had noagreements or understandings, directly or indirectly, with any other person to distribute such shares. In April 2010, we repurchased $3.7million of shares of Class A common stock from Spindrift Partners, L.P. (see “Certain Relationships and Related Party Transactions —Repurchase of Our Securities”).

(8) Wellington Management, as investment adviser to Spindrift Investors (Bermuda), L.P., may be deemed to have shared voting anddispositive power over the shares held by Spindrift Investors (Bermuda), L.P. Spindrift Investors (Bermuda), L.P. is affiliated with one ormore registered broker-dealers. Spindrift Investors (Bermuda), L.P. purchased the shares being registered hereunder in the ordinarycourse of business and, at the time of purchase, had no agreements or understandings, directly or indirectly, with any other person todistribute such shares. In April 2010, we repurchased $4.0 million of shares of Class A common stock from Spindrift Investors(Bermuda), L.P. (see “Certain Relationships and Related Party Transactions — Repurchase of Our Securities”).

(9) Represents shares held of record by General Mills Group Trust (4,218,490 shares) and the Voluntary Employees Beneficiary Assoc.Trust General Mills & Bakery, Confectionary, Tobacco & Grain Millers (345,195 shares), for which the General Mills, Inc. BenefitFinance Committee has sole investment and voting power. A majority vote of the Committee, which currently has four members, isrequired to make any investment or voting decision with respect to these shares. No member of the Committee may act indirectly to voteor sell the shares held by the referenced trusts.

(10) Includes 10,500 shares which Dr. Holditch has the right to acquire within 60 days of January 27, 2012 through the exercise of stockoptions.

(11) Includes 6,750 shares which Mr. Laney has the right to acquire within 60 days of January 27, 2012 through the exercise of stock options.Also includes an aggregate of 242,250 shares held of record by Mr. Laney’s adult children, who gave Mr. Laney voting power of suchshares through a revocable power of attorney and 25,000 shares held of record by Laney Investments Ltd.

(12) Includes 14,250 shares which Dr. Ohnimus has the right to acquire within 60 days of January 27, 2012 through the exercise of stockoptions.

(13) Includes 1,500 shares which Mr. Ryan has the right to acquire within 60 days of January 27, 2012 through the exercise of stock options.

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(14) Includes 174,625 shares held of record by JAMAL Enterprises, LP, for which Mr. Mitchell has sole voting and investment power.

(15) Includes 15,000 shares which Mr. King has the right to acquire within 60 days of January 27, 2012 through the exercise of stock options.The column for Class A common stock includes 150,000 shares of Class A common stock issuable upon the automatic conversion ofMr. King’s shares of Class B common stock at the consummation of this offering. Also includes an aggregate of 48,375 shares held ofrecord by Mr. King’s three minor or college age children.

(16) Represents shares that will be acquired by the holder prior to consummation of this offering in connection with the exercise by suchholder of certain stock options.

(17) Includes 32,500 shares which Mr. Robinson has the right to acquire within 60 days of January 27, 2012 through the exercise of stockoptions and 42,000 shares held of record by his Individual Retirement Account. Mr. Robinson pledged 80,000 shares of common stock tous in connection with the loan program. This pledge was to secure our guaranty to Comerica Bank regarding Mr. Robinson’s loan. Ourboard of directors terminated the loan program on April 7, 2011 and Mr. Robinson terminated the pledge in January 2012. Mr. Robinsonis our Vice President — Reservoir Engineering and is a party to an employment agreement with us (see “Compensation of NamedExecutive Officers — Discussion Regarding Summary Compensation Table and Grants of Plan-Based Awards Table”). In addition, Mr.Robinson has had other material relationships with us within the past three years (see “Certain Relationships and Related PartyTransactions — Loan Program” and “Certain Relationships and Related Party Transactions — Repurchase of Our Securities”).

(18) Includes 82,500 shares which Mr. Lancaster has the right to acquire within 60 days of January 27, 2012 through the exercise of stockoptions and 73,500 shares held of record by his Individual Retirement Account. Mr. Lancaster pledged 120,000 shares of common stockto us in connection with the loan program. This pledge was to secure our guaranty to Comerica Bank regarding Mr. Lancaster’s loan. Ourboard of directors terminated the loan program on April 7, 2011 and Mr. Lancaster terminated the pledge in January 2012. Mr. Lancasteris our Executive Vice President, Chief Operating Officer and Chief Financial Officer and is a party to an employment agreement with us(see “Compensation of Named Executive Officers — Discussion Regarding Summary Compensation Table and Grants of Plan-BasedAwards Table”). In addition, Mr. Lancaster has had other material relationships with us within the past three years (see “CertainRelationships and Related Party Transactions — Loan Program,” “Certain Relationships and Related Party Transactions — Repurchaseof Our Securities” and “Certain Relationships and Related Party Transactions — Issuance of Our Securities”).

(19) Includes 95,000 shares which Mr. Hairford has the right to acquire within 60 days of January 27, 2012 through the exercise of stockoptions and 3,000 shares held of record by his Individual Retirement Account. Mr. Hairford pledged 75,000 shares of common stock tous in connection with the loan program. This pledge was to secure our guaranty to Comerica Bank regarding Mr. Hairford’s loan. Ourboard of directors terminated the loan program on April 7, 2011 and Mr. Hairford terminated the pledge in January 2012. Mr. Hairford isour Executive Vice President — Operations and is a party to an employment agreement with us (see “Compensation of Named ExecutiveOfficers — Discussion Regarding Summary Compensation Table and Grants of Plan-Based Awards Table”). In addition, Mr. Hairfordhas had other material relationships with us within the past three years (see “Certain Relationships and Related Party Transactions —Loan Program” and “Certain Relationships and Related Party Transactions — Repurchase of Our Securities”).

(20) Includes 35,000 shares held by Cleveland Capital L.P. for which Mr. Massad is the co-managing member and 39,675 shares held ofrecord by his Individual Retirement Account.

(21) Includes 20,000 shares which Mr. Nicklin has the right to acquire within 60 days of January 27, 2012 through the exercise of stockoptions and 30,000 shares held of record by his Individual Retirement Account.

(22) Includes an aggregate of 278,000 shares which our executive officers and directors as a group have the right to acquire within 60 days ofJanuary 27, 2012 through the exercise of stock options.

(23) Mr. R. Brian Webb, the Chief Investment Officer of Baylor University, has sole voting and investment power with respect to the sharesheld of record by Baylor University.

(24) BlackRock, Inc. is the ultimate parent holding company of BlackRock Advisors, LLC, the Investment Manager to BlackRock AssetAllocation Portfolio. On behalf of BlackRock Advisors, LLC, the respective Investment Manager to BlackRock Asset AllocationPortfolio, Dan Rice, as a Managing Director at BlackRock Advisors, LLC, has voting and investment power over the securities held byBlackRock Asset Allocation Portfolio. Dan Rice expressly disclaims beneficial ownership of all shares held by BlackRock AssetAllocation Portfolio. The table excludes 1,181,222 shares held of record by certain affiliates of BlackRock, Inc., none of which are beingsold in this offering. BlackRock Asset Allocation Portfolio is affiliated with one or more registered broker-dealers. BlackRock AssetAllocation Portfolio purchased the shares being registered hereunder in the ordinary course of business and at the time of purchase, hadno agreements or understandings, directly or indirectly, with any other person to distribute such shares.

(25) Represents shares held of record by Mr. C.A. Rundell Jr.’s Individual Retirement Account for which Mr. Rundell, Jr. has sole voting andinvestment power.

(26) J. Curtis Henderson has sole voting and investment power with respect to the shares held of record by Coterie Capital Partners, Ltd.

(27) Includes 41,760 shares held of record by Mr. McMichael’s Individual Retirement Account for which Mr. McMichael has sole voting andinvestment power.

(28) C. Taylor Yoakam and Joni Yoakam are husband and wife.

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(29) Mr. Richard Lee is Chief Executive Officer of Lee Financial Corp., the General Partner of LFC Energy Resources, Ltd. and has solevoting and investment power with respect to the shares held of record by LFC Energy Resources, Ltd.

(30) Includes 6,900 shares held of record by Mr. Adams’ Individual Retirement Account, none of which are being sold in this offering.

(31) Wellington Management, as investment adviser to Global Natural Resources III, may be deemed to have shared voting and dispositivepower over the shares held by Global Natural Resources III. An affiliate of Citigroup Global Markets Inc., one of the underwriters in thisoffering and a registered broker-dealer, acts as an administrator and provides certain trust services to Global Natural Resources III. Amember of the board of directors and advisors of Global Natural Resources III is an employee of an affiliate of Citigroup Global MarketsInc., and certain investors in Global Natural Resources III are clients of an affiliate of Citigroup Global Markets Inc. Global NaturalResources III purchased the shares being registered hereunder in the ordinary course of business and, at the time of purchase, had noagreements or understandings, directly or indirectly, with any other person to distribute such shares. In April 2010, we repurchased$727,200 of shares of Class A common stock from Global Natural Resources III (see “Certain Relationships and Related PartyTransactions — Repurchase of Our Securities”).

(32) Wellington Management, as investment adviser to Placer Creek Investors Bermuda L.P., may be deemed to have shared voting anddispositive power over the shares held by Placer Creek Investors Bermuda L.P. Placer Creek Investors Bermuda L.P. is affiliated withone or more registered broker-dealers. Placer Creek Investors Bermuda L.P. purchased the shares being registered hereunder in theordinary course of business and, at the time of purchase, had no agreements or understandings, directly or indirectly, with any otherperson to distribute such shares. In April 2010, we repurchased $258,300 of shares of Class A common stock from Placer CreekInvestors Bermuda L.P. (see “Certain Relationships and Related Party Transactions — Repurchase of Our Securities”).

(33) Wellington Management, as investment adviser to Placer Creek Partners L.P., may be deemed to have shared voting and dispositivepower over the shares held by Placer Creek Partners L.P. Placer Creek Partners L.P. is affiliated with one or more registered broker-dealers. Placer Creek Partners L.P. purchased the shares being registered hereunder in the ordinary course of business and, at the time ofpurchase, had no agreements or understandings, directly or indirectly, with any other person to distribute such shares. In April 2010, werepurchased $290,700 of shares of Class A common stock from Placer Creek Partners L.P. (see “Certain Relationships and Related PartyTransactions — Repurchase of Our Securities”)

(34) Includes 137,750 shares held of record by Ms. Funk’s husband, Mr. James M. Funk, none of which are being sold in this offering.

(35) Mr. Jerry V. Swank has sole voting and investment power with respect to the shares held of record by Swank Investment Partnership LPand Swank MLP Convergence Fund LP. Excludes 69,000 shares held of record by Mr. Swank and Mr. Swank’s Individual RetirementAccount.

(36) Includes 50,000 shares which Mr. Barman has the right to acquire within 60 days of January 27, 2012 through the exercise of stockoptions and 13,650 shares held of record by his Individual Retirement Account. Mr. Barman is an employee.

(37) Includes 22,250 shares which Ms. Crawford has the right to acquire within 60 days of January 27, 2012 through the exercise of stockoptions, 2,550 shares held of record by her Individual Retirement Account, and 8,500 shares held of record by the Individual RetirementAccount of her husband. Ms. Crawford is an employee.

(38) Includes 7,250 shares which Ms. Diaz has the right to acquire within 60 days of January 27, 2012 through the exercise of stock options.Ms. Diaz is an employee.

(39) Includes 17,500 shares which Mr. Ernest has the right to acquire within 60 days of January 27, 2012 through the exercise of stockoptions. Mr. Ernest is an employee.

(40) Includes 5,750 shares which Ms. Frazier has the right to acquire within 60 days of January 27, 2012 through the exercise of stockoptions. Ms. Frazier is an employee.

(41) Includes 30,000 shares which Mr. Henk has the right to acquire within 60 days of January 27, 2012 through the exercise of stock options.Mr. Henk is an employee.

(42) Includes 1,250 shares which Ms. Hoevers has the right to acquire within 60 days of January 27, 2012 through the exercise of stockoptions. Ms. Hoevers is an employee.

(43) Includes 42,000 shares which Mr. Juett has the right to acquire within 60 days of January 27, 2012 through the exercise of stock optionsand 9,495 shares held of record in his custodial account for which Mr. Juett has sole voting and investment power. Mr. Juett is anemployee.

(44) Includes 41,750 shares which Mr. London has the right to acquire within 60 days of January 27, 2012 through the exercise of stockoptions. Mr. London is an employee.

(45) Includes 7,250 shares which Ms. Monroe has the right to acquire within 60 days of January 27, 2012 through the exercise of stockoptions. Ms. Monroe is an employee.

(46) Includes 13,250 shares which Ms. Nelson has the right to acquire within 60 days of January 27, 2012 through the exercise of stockoptions. Ms. Nelson is an employee.

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(47) Includes 3,000 shares which Ms. Paine has the right to acquire within 60 days of January 27, 2012 through the exercise of stock options.Ms. Paine is an employee.

(48) Includes 8,750 shares which Ms. Scott has the right to acquire within 60 days of January 27, 2012 through the exercise of stock optionsand 5,610 shares held of record in her custodial account for which Ms. Scott has sole voting and investment power. Ms. Scott is anemployee.

(49) Includes 3,000 shares which Ms. Scott has the right to acquire within 60 days of January 27, 2012 through the exercise of stock options.Ms. Scott is an employee.

(50) Includes 7,500 shares which Mr. Sinclair has the right to acquire within 60 days of January 27, 2012 through the exercise of stockoptions. Mr. Sinclair is an employee.

(51) Includes 1,500 shares which Ms. Suarez has the right to acquire within 60 days of January 27, 2012 through the exercise of stock options.Ms. Suarez is an employee.

(52) Includes 1,500 shares which Ms. Waters-Hudson has the right to acquire within 60 days of January 27, 2012 through the exercise ofstock options. Ms. Waters-Hudson is an employee.

(53) Includes 11,250 shares which Ms. Wayne has the right to acquire within 60 days of January 27, 2012 through the exercise of stockoptions. Ms. Wayne is an employee.

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DESCRIPTION OF CAPITAL STOCK

Our authorized capital stock consists of 82,000,000 shares of common stock, par value $0.01 per share,and 2,000,000 shares of preferred stock, par value $0.01 per share. The common stock is split into twoclasses — 80,000,000 authorized shares of Class A common stock and 2,000,000 authorized shares ofClass B common stock. Upon the closing of this offering, all issued and outstanding shares of Class Bcommon stock will be automatically converted, on a one-for-one basis, into shares of Class A commonstock, and the separate classes of common stock will be eliminated pursuant to the terms of our certificate offormation. In October 2008, our shareholders approved an increase in the number of authorized Class Acommon stock from 40,000,000 to 80,000,000 in connection with our 3-for-1 stock split. At December 30,2011, we had no outstanding shares of preferred stock, 1,030,700 outstanding shares of Class B commonstock, 42,022,493 outstanding shares of Class A common stock and 43,053,193 outstanding shares ofClass A common stock on an as converted basis. Prior to consummation of this offering, we will issue285,000 shares of common stock to certain holders of stock options in connection with the exercise of theirstock options, which shares are included in the total number of shares of Class A common stock outstandingat December 30, 2011 and 243,460 of which will be sold by certain option holders as selling shareholders inthis offering. At December 30, 2011, we had four holders of record of Class B common stock and 496holders of record of our Class A common stock.

Effective upon the closing of this offering, our certificate of formation will be amended to eliminate allreferences to the separate classes of common stock and our capital stock will consist of 80,000,000 shares ofcommon stock, par value $0.01 per share, and 2,000,000 shares of preferred stock, par value $0.01 per share.

Common Stock

Other than the special rights of the Class B common stock described below in this section, the Class Acommon stock and the Class B common stock are identical in all respects. Upon the closing of this offering,all issued and outstanding shares of Class B common stock will be automatically converted, on aone-for-one basis, into shares of Class A common stock, and the separate classes of common stock will beeliminated pursuant to the terms of our certificate of formation.

In the fourth quarter of 2008, we effected a 3-for-1 forward stock split of the Class A common stock.The forward split was effected through a share dividend of two shares of Class A common stock for eachoutstanding share of common stock (including Class B common stock) held by our shareholders of record atOctober 31, 2008.

The holders of the Class B common stock are entitled to be paid cumulative dividends at a per sharerate of $0.26-2/3 annually out of funds legally available for the payment of dividends. These dividendsaccrue and are payable quarterly at the rate of $0.06-2/3 per share of Class B common stock outstanding.Upon the automatic conversion of the outstanding shares of Class B common stock at the closing of thisoffering, the right to dividends will terminate. Any accrued but unpaid dividends existing at the time of suchconversion will be paid to the holders of the Class B common stock upon conversion.

Holders of all of our common stock will be entitled to receive their pro rata shares of dividends in theamounts and at the times declared by our board of directors in its discretion out of funds legally availablefor the payment of dividends.

Subject to any special voting rights of any series of preferred stock that we may issue in the future,each share of common stock has one vote on all matters voted on by our shareholders, including the electionof directors. No share of common stock has any cumulative voting or preemptive rights or is redeemable,

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assessable or entitled to the benefits of any sinking or repurchase fund. Holders of common stock will shareequally in our assets on liquidation after payment or provision for all liabilities and any preferentialliquidation rights of any preferred stock then outstanding. All outstanding shares of common stock are fullypaid and non-assessable.

Preferred Stock

At the direction of our board of directors, we may issue shares of preferred stock from time to time.Our board of directors may, without any action by holders of common stock, adopt resolutions to issuepreferred stock by establishing the number, rights and preferences of, and designating, one or more series ofpreferred stock. No series of preferred stock has been designated and established by our board of directors.The rights of any series of preferred stock may include, among others:

• general or special voting rights;

• preferential liquidation or preemptive rights;

• preferential cumulative or noncumulative dividend rights;

• redemption or put rights; and

• conversion or exchange rights.

We may issue shares of, or rights to purchase shares of, preferred stock the terms of which might:

• adversely affect voting or other rights evidenced by, or amounts otherwise payable with respect to,the common stock;

• discourage an unsolicited proposal to acquire us; or

• facilitate a particular business combination involving us.

Any of these actions could discourage a transaction that some or a majority of our shareholders mightbelieve to be in their best interests or in which our shareholders might receive a premium for their stockover our then market price.

Business Combinations under Texas Law

A number of provisions of Texas law, our certificate of formation and bylaws could make moredifficult the acquisition of Matador by means of a tender offer, a proxy contest or otherwise and the removalof incumbent officers and directors. These provisions are intended to discourage coercive takeover practicesand inadequate takeover bids and to encourage persons seeking to acquire control of Matador to negotiatefirst with our board of directors.

We are subject to the provisions of Title 2, Chapter 21, Subchapter M of the Texas BusinessOrganizations Code (the “Texas Business Combination Law”). That law provides that a Texas corporationmay not engage in specified types of business combinations, including mergers, consolidations and assetsales, with a person, or an affiliate or associate of that person, who is an “affiliated shareholder.” An“affiliated shareholder” is generally defined as the holder of 20% or more of the corporation’s voting shares,for a period of three years from the date that person became an affiliated shareholder. The law’s prohibitionsdo not apply if:

• the business combination or the acquisition of shares by the affiliated shareholder was approved bythe board of directors of the corporation before the affiliated shareholder became an affiliatedshareholder; or

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• the business combination was approved by the affirmative vote of the holders of at least two-thirdsof the outstanding voting shares of the corporation not beneficially owned by the affiliatedshareholder, at a meeting of shareholders called for that purpose, not less than six months after theaffiliated shareholder became an affiliated shareholder.

Because we have more than 100 shareholders, we are considered an “issuing public corporation” forpurposes of this law. The Texas Business Combination Law does not apply to the following:

• the business combination of an issuing public corporation: where the corporation’s original charteror bylaws contain a provision expressly electing not to be governed by the Texas BusinessCombination Law; or that adopts an amendment to its charter or bylaws, by the affirmative vote ofthe holders, other than affiliated shareholders, of at least two-thirds of the outstanding voting sharesof the corporation, expressly electing not to be governed by the Texas Business Combination Lawand so long as the amendment does not take effect for 18 months following the date of the vote anddoes not apply to a business combination with an affiliated shareholder who became affiliated on orbefore the effective date of the amendment;

• a business combination of an issuing public corporation with an affiliated shareholder that becamean affiliated shareholder inadvertently, if the affiliated shareholder divests itself, as soon aspossible, of enough shares to no longer be an affiliated shareholder and would not at any timewithin the three-year period preceding the announcement of the business combination have been anaffiliated shareholder but for the inadvertent acquisition;

• a business combination with an affiliated shareholder who became an affiliated shareholder througha transfer of shares by will or intestacy and continuously was an affiliated shareholder until theannouncement date of the business combination; and

• a business combination of a corporation with its wholly owned Texas subsidiary if the subsidiary isnot an affiliate or associate of the affiliated shareholder other than by reason of the affiliatedshareholder’s beneficial ownership of voting shares of the corporation.

Neither our certificate of formation nor our bylaws contain any provision expressly providing that wewill not be subject to the Texas Business Combination Law. The Texas Business Combination Law mayhave the effect of inhibiting a non-negotiated merger or other business combination involving our company,even if that event would be beneficial to our shareholders.

Action by Consent

Our bylaws and Texas law provide that any action that can be taken at any special or annual meeting ofshareholders may be taken by unanimous written consent of all shareholders entitled to vote.

Certain Charter and Bylaw Provisions

Our certificate of formation and bylaws contain, or will contain upon completion of this offering,certain provisions that could discourage potential takeover attempts and make it more difficult for ourshareholders to change management or receive a premium for their shares. These provisions include:

• authorization for our board of directors to issue preferred stock without shareholder approval;

• a classified board of directors so that not all members of our board of directors are elected at onetime;

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• the prohibition of cumulative voting in the election of directors; and

• a limitation on the ability of shareholders to call special meetings to those owning at least 25% ofour outstanding shares of common stock.

Limitation of Liability and Indemnification of Officers and Directors

Our certificate of formation provides that our directors are not liable to the company or its shareholdersfor monetary damages for an act or omission in their capacity as a director. A director may, however, befound liable for:

• any breach of the director’s duty of loyalty to the company or its shareholders;

• acts or omissions not in good faith that constitute a breach of the director’s duty to the company;

• acts or omissions that involve intentional misconduct or a knowing violation of law;

• any transaction from which the director receives an improper benefit; or

• acts or omissions for which the liability is expressly provided by an applicable statute.

Our certificate of formation also provides that we will indemnify our directors, and may indemnify ourofficers, employees and agents, to the fullest extent permitted by applicable Texas law from any expenses,liabilities or other matters. Insofar as indemnification for liabilities arising under the Securities Act may bepermitted for directors, officers and controlling persons of Matador under our certificate of formation, it isthe position of the SEC that such indemnification is against public policy as expressed in the Securities Actand is, therefore, unenforceable.

Indemnification Agreements

We have entered into indemnification agreements with each of our officers and directors. Under theseagreements, we have agreed to indemnify the director or officer who acts on behalf of Matador and is madeor threatened to be made a party to any action or proceeding for expenses, judgments, fines and amountspaid in settlement that are actually and reasonably incurred in connection with the action or proceeding. Theindemnity provisions apply whether the action was instituted by a third party or by us. Generally, theprincipal limitation on our obligation to indemnify the director or officer will be if it is determined by acourt of law, not subject to further appeal, that indemnification is prohibited by applicable law or theprovisions of the indemnification agreement.

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is Registrar and Transfer Company.

Listing

Our common stock has been approved for listing on the NYSE under the symbol “MTDR.”

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our common stock. Future sales of ourcommon stock in the public market, or the availability of such shares for sale in the public market, couldadversely affect market prices prevailing from time to time. As described below, only a limited number ofshares will be available for sale shortly after this offering due to contractual and legal restrictions on resale.Nevertheless, sales of a substantial number of shares of our common stock in the public market after suchrestrictions lapse, or the perception that those sales may occur, could adversely affect the prevailing marketprice at such time and our ability to raise equity-related capital at a time and price we deem appropriate.

Sales of Restricted Shares

Upon the closing of this offering, we will have outstanding an aggregate of 54,719,860 shares ofcommon stock, and in addition to the shares sold in this offering by us and the selling shareholders,54,584,284 shares of common stock will be freely tradable without restriction or further registration underthe Securities Act, except to the extent the shares are held by any of our “affiliates” as such term is definedin Rule 144 of the Securities Act.

All remaining shares of common stock held by existing shareholders will be deemed “restrictedsecurities” as such term is defined under Rule 144. The restricted securities were issued and sold by us inprivate transactions and are eligible for public sale only if registered under the Securities Act or if theyqualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which rulesare summarized below.

42,440,339 of our shares, including all shares held by our officers and directors and the sellingshareholders, except for the shares offered by the selling shareholders in this offering, are subject to lock-upagreements that prohibit the disposition of those shares during the 180-day period beginning on the date ofthe final prospectus related to this offering, except with the prior written consent of RBC Capital Markets,LLC and subject to certain exceptions. After the expiration of the 180-day restricted period, these sharesmay be sold in the public market in the United States, subject to prior registration in the United States, ifrequired, or reliance upon an exemption from U.S. registration, including, in the case of shares held byaffiliates or control persons, compliance with the volume restrictions of Rule 144. See “Underwriters” for adescription of these lockup provisions.

Rule 144

In general, under Rule 144 as currently in effect, once we have been a reporting company subject to thereporting requirements of Section 13 or 15(d) of the Exchange Act for 90 days, a person (or persons whoseshares are aggregated) who is not deemed to have been an affiliate of ours at any time during the threemonths preceding a sale, and who has beneficially owned restricted securities within the meaning ofRule 144 for at least six months (including any period of consecutive ownership of preceding non-affiliatedholders) would be entitled to sell those shares, subject only to the availability of current public informationabout us. A non-affiliated person who has beneficially owned restricted securities within the meaning ofRule 144 for at least one year would be entitled to sell those shares without regard to the provisions ofRule 144.

Once we have been a reporting company subject to the reporting requirements of Section 13 or 15(d)of the Exchange Act for 90 days, a person (or persons whose shares are aggregated) who is deemed to be anaffiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at

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least six months would be entitled to sell within any three-month period a number of shares that does notexceed the greater of one percent of the then outstanding shares of our common stock or the average weeklytrading volume of our common stock reported through the NYSE during the four calendar weeks precedingthe filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, noticerequirements and the availability of current public information about us.

Rule 701

Employees, directors, officers, consultants or advisors who purchase shares from us in connection witha compensatory stock or option plan or other written compensatory agreement in accordance with Rule 701before the effective date of the registration statement are entitled to sell such shares 90 days after theeffective date of the registration statement in reliance on Rule 144 without having to comply with theholding period requirement of Rule 144 and, in the case of non-affiliates, without having to comply with thepublic information, volume limitation or notice filing provisions of Rule 144. The SEC has indicated thatRule 701 will apply to typical stock options granted by an issuer before it becomes subject to the reportingrequirements of the Exchange Act, along with the shares acquired upon exercise of such options, includingexercises after the date of this prospectus.

Stock Issued Under Employee Plans

We intend to file a registration statement on Form S-8 under the Securities Act to register stockissuable under our 2003 Stock and Incentive Plan and our 2012 Long-Term Incentive Plan. This registrationstatement is expected to be filed following the effective date of the registration statement of which thisprospectus is a part and will be effective upon filing. Accordingly, shares registered under such registrationstatement will be available for sale in the open market following the effective date, unless such shares aresubject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lockuprestrictions described above.

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MATERIAL U.S. FEDERAL INCOME AND ESTATE TAXCONSIDERATIONS TO NON-U.S. HOLDERS

The following is a general discussion of the material U.S. federal income and estate tax consequencesof the acquisition, ownership and disposition of our common stock to a non-U.S. holder. Except asspecifically provided below (see “— Estate Tax”), for the purpose of this discussion, a non-U.S. holder isany beneficial owner of our common stock that is not for U.S. federal income tax purposes any of thefollowing:

• an individual citizen or resident of the United States;

• a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) createdor organized in the United States or under the laws of the United States or any state or the Districtof Columbia;

• a partnership (or other entity treated as a partnership for U.S. federal income tax purposes);

• an estate whose income is subject to U.S. federal income tax regardless of its source; or a trust(x) whose administration is subject to the primary supervision of a U.S. court and which has one ormore U.S. persons who have the authority to control all substantial decisions of the trust or (y) thatwas in existence on August 20, 1996, was treated as a U.S. person at the previous day and hasmade a valid election to continue to be treated as a U.S. person.

If a partnership (or an entity treated as a partnership for U.S. federal income tax purposes) holds ourcommon stock, the tax treatment of a partner in the partnership will generally depend on the status of thepartner and upon the activities of the partnership. Accordingly, we urge partnerships that hold our commonstock and partners in such partnerships to consult their own tax advisors regarding the tax treatment ofholding our common stock.

This discussion assumes that a non-U.S. holder will hold our common stock issued pursuant to thisoffering as a capital asset (generally, property held for investment). This discussion does not address allaspects of U.S. federal income taxation or any aspects of state, local or non-U.S. taxation, nor does itconsider any U.S. federal income tax considerations that may be relevant to non-U.S. holders which may besubject to special treatment under U.S. federal income tax laws, including, without limitation,U.S. expatriates, controlled foreign corporations, passive foreign investment companies, insurancecompanies, tax-exempt or governmental organizations, dealers in securities or currency, banks or otherfinancial institutions and investors that hold our common stock as part of a hedge, straddle or conversiontransaction. Furthermore, the following discussion is based on current provisions of the Internal RevenueCode of 1986, as amended, and Treasury Regulations and administrative and judicial interpretations thereof,all as in effect on the date hereof, and all of which are subject to change, possibly with retroactive effect.

This section does not address all U.S. federal income and estate tax matters applicable to a non-U.S.holder. Because each prospective investor may have unique circumstances beyond the scope of thediscussion herein, we encourage each prospective investor to consult with its own tax advisor regarding theapplication of the U.S. federal income tax laws to its particular situation as well as any tax consequencesarising under U.S. estate laws and under the laws of any state, local or foreign taxing jurisdiction or underany applicable tax treaty.

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Dividends

If we pay dividends on our common stock, those payments will constitute dividends for U.S. taxpurposes to the extent paid from our current or accumulated earnings and profits, as determined underU.S. federal income tax principles. To the extent those dividends exceed our current and accumulatedearnings and profits, the dividends will constitute a return of capital and will first reduce a holder’s adjustedtax basis in its common stock, but not below zero, and then will be treated as gain from the sale of thecommon stock (see “— Gain on Disposition of Common Stock”).

Any dividend paid out of earnings and profits to a non-U.S. holder of our common stock generally willbe subject to U.S. withholding tax either at a rate of 30% of the gross amount of the dividend or such lowerrate as may be specified by an applicable tax treaty. To receive the benefit of a reduced treaty rate, anon-U.S. holder generally must provide us with an Internal Revenue Service (“IRS”) Form W-8BENcertifying qualification for the reduced rate.

Dividends received by a non-U.S. holder that are effectively connected with a U.S. trade or businessconducted by the non-U.S. holder will be exempt from such withholding tax. To obtain this exemption, thenon-U.S. holder must provide us with an IRS Form W-8ECI properly certifying such exemption. Sucheffectively connected dividends, although not subject to withholding tax, will be subject to U.S. federalincome tax on a net income basis at the same graduated U.S. tax rates generally applicable to U.S. persons,net of certain deductions and credits, subject to any applicable tax treaty providing otherwise. In addition tothe income tax described above, dividends received by corporate non-U.S. holders that are effectivelyconnected with a U.S. trade or business of the corporate non-U.S. holder may be subject to a branch profitstax at a rate of 30% or such lower rate as may be specified by an applicable tax treaty.

In certain circumstances, amounts received by a non-U.S. holder upon the redemption of our commonstock may be treated as a distribution in the nature of a dividend with respect to the common stock, ratherthan as a payment in exchange for the common stock that results in the recognition of capital gain or loss. Inthese circumstances, the redemption payment would be included in gross income as a dividend to the extentthat such payment is made out of our earnings and profits (as described above). The determination ofwhether a redemption of common stock will be treated as a distribution, rather than as a payment inexchange for the common stock, will depend on whether and to what extent the redemption reduces thenon-U.S. holder’s ownership in us. The rules applicable to redemptions are complex, and each non-U.S.holder should consult its own tax advisor to determine the consequences of a redemption to it.

Gain on Disposition of Common Stock

A non-U.S. holder generally will not be subject to U.S. federal income tax on any gain realized uponthe sale or other disposition of our common stock unless:

• the gain is effectively connected with a U.S. trade or business of the non-U.S. holder and, if required byan applicable tax treaty, is attributable to a U.S. permanent establishment maintained by suchnon-U.S. holder;

• the non-U.S. holder is an individual who is present in the United States for a period or periodsaggregating 183 days or more during the calendar year in which the sale or disposition occurs andcertain other conditions are met; or

• we are or have been a “U.S. real property holding corporation” for U.S. federal income taxpurposes and the non-U.S. holder holds or has held, directly or indirectly, at any time within theshorter of the five-year period preceding the disposition or the non-U.S. holder’s holding period,

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more than 5% of our common stock. Generally, a corporation is a U.S. real property holdingcorporation if the fair market value of its U.S. real property interests equals or exceeds 50% of thesum of the fair market value of its worldwide real property interests and its other assets used orheld for use in a trade or business. If we are or have been a U.S. real property holding corporationand our common stock is not regularly traded on an established securities market, then the gainrecognized on the sale or other disposition of our common stock by a non-U.S. holder would besubject to U.S. federal income tax regardless of the amount of the non-U.S. holder’s ownershippercentage.

We believe that we are, and will remain for the foreseeable future, a “U.S. real property holdingcorporation” for U.S. federal income tax purposes.

Unless an applicable tax treaty provides otherwise, gain described in the first and third bullet pointsabove will be subject to U.S. federal income tax on a net income basis at the same graduated U.S. tax ratesgenerally applicable to U.S. persons. A branch profits tax may apply to certain of such gains. In additiongain described in the third bullet point may also be subject to certain withholding rules.

Gain described in the second bullet point above (which may be offset by U.S. source capital losses,provided that the non-U.S. holder has timely filed U.S. federal income tax returns with respect to suchlosses) generally will be subject to a flat 30% U.S. federal income tax.

Backup Withholding and Information Reporting

Generally, we must report annually to the IRS the amount of dividends paid to each non-U.S. holder,and the amount, if any, of tax withheld with respect to those dividends. A similar report is sent to eachnon-U.S. holder. These information reporting requirements apply even if withholding was not required.Pursuant to tax treaties or other agreements, the IRS may make its reports available to tax authorities in therecipient’s country of residence.

Payments of dividends to a non-U.S. holder may be subject to backup withholding (currently at a rateof 28%, and scheduled to increase to a rate of 31% on January 1, 2013) unless the non-U.S. holderestablishes an exemption, for example, by properly certifying its non-U.S. status on an IRS Form W-8BENor another appropriate version of IRS Form W-8. Notwithstanding the foregoing, backup withholding alsomay apply if we have actual knowledge, or reason to know, that the beneficial owner is a U.S. person that isnot an exempt recipient.

Payments of the proceeds from sale or other disposition by a non-U.S. holder of our common stockeffected outside the United States by or through a foreign office of a broker generally will not be subject toinformation reporting or backup withholding. However, information reporting will apply to those paymentsif the broker does not have documentary evidence that the holder is a non-U.S. holder, an exemption is nototherwise established and the broker has certain relationships with the United States.

Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our common stockeffected by or through a U.S. office of a broker generally will be subject to information reporting andbackup withholding (currently at a rate of 28%, and scheduled to increase to a rate of 31% on January 1,2013) unless the non-U.S. holder establishes an exemption, for example, by properly certifying itsnon-U.S. status on an IRS Form W-8BEN or another appropriate version of IRS Form W-8.Notwithstanding the foregoing, information reporting and backup withholding also may apply if the brokerhas actual knowledge, or reason to know, that the holder is a U.S. person that is not an exempt recipient.

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Backup withholding is not an additional tax. Rather, the U.S. income tax liability of persons subject tobackup withholding will be reduced by the amount of tax withheld. If withholding results in anoverpayment of taxes, a refund may be obtained, provided that the required information is timely furnishedto the IRS.

Estate Tax

Our common stock owned or treated as owned by an individual who is not a citizen or resident of theUnited States (as specifically defined for U.S. federal estate tax purposes) at the time of death will beincludible in the individual’s gross estate for U.S. federal estate tax purposes and may be subject toU.S. federal estate tax unless an applicable estate tax treaty provides otherwise.

Legislation Affecting Common Stock Held Through Foreign Accounts

Recently enacted legislation generally will impose a U.S. federal withholding tax of 30% on dividendsand the gross proceeds of a disposition of our common stock paid after December 31, 2012 to a “foreignfinancial institution” (as specifically defined under these rules) unless such institution enters into anagreement with the U.S. government to withhold on certain payments and to collect and provide to the U.S.tax authorities substantial information regarding U.S. account holders of such institution (which includescertain equity and debt holders of such institution, as well as certain account holders that are foreign entitieswith U.S. owners). The legislation also will generally impose a U.S. federal withholding tax of 30% ondividends and the gross proceeds of a disposition of our common stock paid after December 31, 2012 to anon-financial foreign entity unless such entity provides the withholding agent with certain informationrelating to the direct and indirect U.S. owners of the entity. Under certain circumstances, a non-U.S. holdermight be eligible for refunds or credits of such taxes. Prospective investors are encouraged to consult withtheir own tax advisors regarding the possible implications of this legislation on their investment in ourcommon stock.

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UNDERWRITERS

Under the terms and subject to the conditions contained in an underwriting agreement datedFebruary 1, 2012, we and the selling shareholders have agreed to sell to the underwriters named below, forwhom RBC Capital Markets, LLC and Citigroup Global Markets Inc. are acting as representatives, thefollowing respective numbers of shares of common stock:

NameNumber of

Shares

RBC Capital Markets, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,133,334Citigroup Global Markets Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,666,667Jefferies & Company, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,466,667Howard Weil Incorporated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 733,333Stifel, Nicolaus & Company, Incorporated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 733,333Simmons & Company International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 533,333Stephens Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 600,000Comerica Securities, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 466,667

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,333,334

The underwriting agreement provides that the underwriters are obligated, severally and not jointly, topurchase all the shares of common stock offered by us. The underwriting agreement also provides that if anunderwriter defaults, the purchase commitments of non-defaulting underwriters may be increased or thisoffering may be terminated.

We have granted to the underwriters a 30-day option to purchase up to 700,000 additional shares at theoffering price less the underwriting discounts and commissions. The selling shareholders have granted to theunderwriters a 30-day option to purchase up to an aggregate of 1,300,000 additional shares at the offeringprice less the underwriting discounts and commissions. The options may be exercised only to cover any over-allotments of common stock. The option may be exercised only to cover any over-allotments of commonstock.

The underwriters propose to offer the shares of common stock directly to the public at the offeringprice on the cover page of this prospectus and to selling group members at that price less a sellingconcession not in excess of $0.49 per share. After this offering, the representatives may change the offeringprice and concession.

Except as described below, the following table summarizes the compensation we and the sellingshareholders will pay:

Per Share Total

WithoutOver-

AllotmentWith Over-Allotment

WithoutOver-

AllotmentWith Over-Allotment

Underwriting discounts and commissions paid by us . . . . . . . . . . . . . . . . . . . . . . . . $0.81 $0.81 $9,450,000 $10,017,000Underwriting discounts paid by selling shareholders(1) . . . . . . . . . . . . . . . . . . . . . . . $0.81 $0.81 $1,152,798 $ 2,205,798

(1) Certain holders of stock options to purchase 285,000 shares of common stock are exercising such options prior to consummation of thisoffering and selling 243,460 of these shares of common stock in this offering. These selling shareholders will not be required to pay anyunderwriting discounts or commissions in connection with the sale of their shares to the underwriters.

The expenses of this offering that are payable by us are estimated to be $3.0 million, exclusive ofunderwriting discounts and commissions.

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The underwriters have informed us that they do not intend sales to discretionary accounts in excess of5% of the total number of shares of common stock offered by them.

99.2% of our shares prior to this offering, including all shares held by our officers and directors and theselling shareholders, are subject to lock-up agreements with RBC Capital Markets, LLC, on behalf of theunderwriters, that prohibit during the period ending 180 days after the date of the final prospectus related tothis offering (the “lockup period”):

• directly or indirectly, selling, offering, contracting or granting any option to sell or short sell,granting any option, right or warrant to purchase, pledging, transferring, establishing an open “putequivalent position”, lending or otherwise disposing of any shares of our common stock, options,rights or warrants to acquire shares of our common stock, or securities exchangeable or exercisablefor or convertible into shares of our common stock owned either of record or beneficially;

• entering into any swap or other arrangement that transfers, in whole or in part, the economicconsequences of the ownership of our common stock; or

• publicly announcing an intention to do any of the foregoing.

These agreements also apply to any sale of locked up shares upon exercise of any options to purchaseshares of common stock and are subject to certain exceptions, including:

• sales of common stock to the underwriters in this offering;

• the award of options or other purchase rights or shares of our common stock pursuant to ouremployee benefits plans;

• issuances of shares of common stock or securities convertible into or exercisable or exchangeablefor shares of common stock pursuant to the exercise of warrants, options or other convertible orexchangeable securities, including shares of convertible preferred stock, in each case which areoutstanding on the date hereof; and

• filing with the SEC a registration statement under the Securities Act on Form S-8 with respect tosecurities issued pursuant to an employee benefit plan.

Notwithstanding the foregoing, our officers, directors and shareholders will be permitted to:

• abide by any obligations regarding shares of common stock or any security convertible intocommon stock under any existing pledge, margin account or similar agreement, including, but notlimited to, sales and transfers of such securities;

• transfer shares of common stock or any security convertible into common stock as a bona fide gift;

• distribute shares of common stock or any security convertible into common stock to limitedpartners, general partners, members or shareholders;

• transfer shares of common stock or any security convertible into common stock to family membersor a trust established for the benefit of family members;

• transfer shares of common stock or any security convertible into common stock to entities wherethe party to the lockup is the beneficial owner of all shares of common stock or our other securitiesheld by the entity;

• receive shares of common stock upon the exercise of an option or warrant or in connection with thevesting of restricted stock or restricted stock units;

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• transfer shares of common stock to the company in a transaction exempt from Section 16(b) of theExchange Act solely in connection with the payment of taxes due in connection with any suchexercise or vesting; and

• pursuant to section 5(x) of the underwriting agreement, upon five days advance written notice toRBC Capital Markets, LLC, RBC will consent to a transfer by an existing shareholder of shares ofcommon stock directly to another existing shareholder that has also signed a lock-up agreementwith RBC and that acknowledges to RBC that the shares will be subject to the lock-up agreementso long as such transfer would not require the transferor to file a Form 4 pursuant to Section 16 ofthe Exchange Act or an amendment to any Schedule 13D or 13G pursuant to Section 13 of theExchange Act.

It is a pre-condition to any such permitted transfer that the transferee executes and delivers to RBC alock-up agreement in form and substance similar to the transferor’s agreement with RBC.

In addition, if (1) during the last 17 days of the restricted period, we issue an earnings release ormaterial news or a material event relating to us occurs; or (2) prior to the expiration of the restricted period,we announce that we will release earnings results during the 16-day period beginning on the last day of therestricted period, the restrictions described above will continue to apply until the expiration of the 18-dayperiod beginning on the issuance of the earnings release or the occurrence of the material news or materialevent.

RBC Capital Markets, LLC may consent in its sole discretion to a release of the transfer restrictions inthe lock-up agreements. The lock-up agreements provided by our largest group of shareholders, WellingtonManagement Company, LLP and the shareholders advised by it, or the Wellington Management group, whobeneficially own 17.5% of our outstanding shares of Class A common stock, also provide that if anyshareholder, director, executive officer or other person party to a lock-up agreement is in any way releasedfrom, or receives a waiver of, any of its obligations pursuant to a lock-up agreement, the members of theWellington Management group will be contemporaneously released or waived from their obligations undertheir lock-up agreements to the extent of the same percentage of their holdings of shares as was granted tothe person receiving the release or waiver. This provision does not apply to

• any releases or waivers granted to any party to a lock-up agreement (other than the WellingtonManagement group and other than persons or entities that are identified in “Principal and SellingShareholders” as beneficially owning 5% or more of the outstanding shares of our common stock,and any persons or entities identified in a footnote associated with such persons or entities) solelyto accommodate a personal hardship until the aggregate number of shares covered by such releasesor waivers exceeds 250,000 shares, in which case the number of shares to be released or waived forthe members of the Wellington Management group will be equal to the aggregate number of sharesreleased or waived in excess of 250,000 to be allocated among them as they may determine;

• shares to be sold in this offering by any selling shareholders; or

• releases or waivers granted to any shareholder (other than the Wellington Management group andother than persons or entities that are identified in “Principal and Selling Shareholders” asbeneficially owning 5% or more of the outstanding shares of our common stock, and any personsor entities identified in a footnote associated with such persons or entities) pursuant to section 5(x)of the underwriting agreement, as described above.

We have agreed not to file any registration statement with respect to our common stock or other equitysecurities (other than on Form S-8 as described above), and our directors, officers and other holders of ourequity securities will waive all registration rights with respect to this offering.

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We and the selling shareholders have agreed to indemnify the underwriters against liabilities under theSecurities Act, or contribute to payments that the underwriters may be required to make in that respect. Inaddition, we and the selling shareholders have agreed to indemnify Jefferies & Company, Inc. againstliabilities incurred in connection with acting as a qualified independent underwriter, including liabilitiesunder the Securities Act.

Our common stock has been approved for listing on the NYSE under the symbol “MTDR”.

Prior to this offering, there has been no public market for our common stock. The initial public offeringprice has been determined by negotiations between us and the representatives of the underwriters. Amongthe factors considered in determining the initial public offering price were our prospects and the prospectsof our industry in general, our financial operating information in recent periods, an assessment of ourmanagement, the general condition of the securities markets and the recent market prices of, and demandfor, publicly traded common stock of generally comparable companies.

In the ordinary course of business, certain of the underwriters and their affiliates have provided andmay in the future provide financial advisory, investment banking and general financing and bankingservices for us and our affiliates for customary fees.

In connection with this offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation Munder the Exchange Act, including:

• stabilizing transactions that permit bids to purchase the underlying security so long as thestabilizing bids do not exceed a specified maximum;

• over-allotment, which involves sales by the underwriters of shares in excess of the number ofshares the underwriters are obligated to purchase, which creates a syndicate short position. Theshort position may be either a covered short position or a naked short position. In a covered shortposition, the number of shares over-allotted by the underwriters is not greater than the number ofshares that they may purchase in the over-allotment option. In a naked short position, the numberof shares involved is greater than the number of shares in the over-allotment option. Theunderwriters may close out any covered short position by exercising their over-allotment optionand/or purchasing shares in the open market;

• syndicate covering transactions, which involve purchases of the common stock in the open marketafter the distribution has been completed in order to cover syndicate short positions. In determiningthe source of shares to close out the short position, the underwriters will consider, among otherthings, the price of shares available for purchase in the open market as compared to the price atwhich they may purchase shares through the over-allotment option. If the underwriters sell moreshares than could be covered by the over-allotment option, a naked short position, the position canonly be closed out by buying shares in the open market. A naked short position is more likely to becreated if the underwriters are concerned that there could be downward pressure on the price of theshares in the open market after pricing that could adversely affect investors who purchase in thisoffering; and

• penalty bids, which permit the representatives to reclaim a selling concession from a syndicatemember when the common stock originally sold by the syndicate member is purchased in astabilizing or syndicate covering transaction to cover syndicate short positions.

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These stabilizing transactions, over-allotment transactions, syndicate covering transactions and penaltybids may have the effect of raising or maintaining the market price of our common stock or preventing orretarding a decline in the market price of the common stock. As a result, the price of our common stock maybe higher than the price that might otherwise exist in the open market. These transactions may be effectedon the NYSE or otherwise and, if commenced, may be discontinued at any time.

A prospectus in electronic format may be made available on the websites maintained by one or more ofthe underwriters or selling group members, if any, participating in this offering. The representatives mayagree to allocate a number of shares to underwriters and selling group members for sale to their onlinebrokerage account holders.

Directed Share Program

At our request, certain of the underwriters have reserved up to approximately 11% of the commonstock being offered by this prospectus (excluding any shares to be issued upon exercise of the over-allotment option) for sale at the initial public offering price to our directors, officers, employees,consultants, business or other associates and certain of our existing shareholders. The sales will be made byRBC Capital Markets, LLC through a directed share program. We do not know if these persons will chooseto purchase all or any portion of these reserved shares, but any purchases they do make will reduce thenumber of shares available to the general public. Any reserved shares which are not so purchased will beoffered by the underwriters to the general public on the same basis as the other shares offered by thisprospectus. Participants in the directed share program may be subject to a 180-day lockup with respect toany shares sold to them pursuant to that program. This lockup will have similar restrictions and an identicalextension provision to the lockup agreements described above. Any shares sold in the directed shareprogram to our directors or executive officers will also be subject to the lockup agreements described above.We have agreed to indemnify RBC Capital Markets, LLC and the underwriters in connection with thedirected share program, including for the failure of any participant to pay for its shares.

The following directors and executive officers have indicated to us that they currently intend topurchase the following amounts of common stock in the directed share program in this offering at the initialprice to the public:

Director or Executive Officer Amount

Joseph Wm. Foran(1) $2,000,000Wade I. Massad(2) 250,000David M. Laney(3) 600,000Charles L. Gummer 330,000Margaret B. Shannon 200,000Gregory E. Mitchell(4) 200,000

(1) $1,500,000 of shares are expected to be purchased by Mr. Foran and $500,000 of shares are expected to be purchased by SageResources, Ltd., a limited partnership owned by the Foran family, including Mr. Foran.

(2) Shares may be purchased by Mr. Massad or an entity over which Mr. Massad has investment and voting authority.(3) $300,000 of shares are expected to be purchased by Laney Investments Ltd.(4) Shares are expected to be purchased by JAMAL Enterprises, LP, for which Mr. Mitchell has sole voting and investment authority.

These prospective purchasers have the right to purchase these shares, but are under no obligation topurchase any shares in this offering and their interest in purchasing shares in this offering is not acommitment to do so. The underwriters will receive the same discount from shares of our common stockpurchased by such directors and officers as they will from other shares of our common stock sold to the

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public in this offering. Any shares purchased by such directors and officers will be subject to lock-uprestrictions described in the section entitled “Underwriters.”

Conflicts of Interest

The underwriters and their respective affiliates are full service financial institutions engaged in variousactivities, which may include securities trading, commercial and investment banking, financial advisory,investment management, investment research, principal investment, hedging, financing and brokerageactivities. Certain of the underwriters and their respective affiliates have, from time to time, performed, andmay in the future perform, various financial advisory and investment banking services for us, for which theyreceived or will receive customary fees and expenses. For example, affiliates of Comerica Securities, Inc.are counterparties to our hedging arrangements and provide commercial banking services for our treasurymanagement function.

Affiliates of RBC Capital Markets, Citigroup Global Markets Inc. and Comerica Securities, Inc. arelenders, and Comerica Bank, an affiliate of Comerica Securities, Inc., acts as administrative agent for thelenders, under our amended and restated senior secured revolving credit agreement. Because more than 5%of the proceeds of this offering will be used to repay indebtedness under the credit facility, a “conflict ofinterest” under Rule 5121 of FINRA is therefore deemed to exist. Pursuant to FINRA Rule 5121, a“qualified independent underwriter” meeting certain standards must participate in the preparation of theregistration statement of which this prospectus forms a part and exercise the usual standards of duediligence with respect thereto. Jefferies & Company, Inc. has assumed the responsibilities of acting as thequalified independent underwriter in this offering, and Jefferies & Company, Inc. will not receive additionalcompensation for that role. Affiliates of RBC Capital Markets, Citigroup Global Markets Inc. and ComericaSecurities, Inc. will not confirm sales of the common stock to any account over which they havediscretionary authority without the prior written approval of the customer.

In the ordinary course of their various business activities, the underwriters and their respectiveaffiliates may make or hold a broad array of investments and actively trade debt and equity securities (orrelated derivative securities) and financial instruments (including bank loans) for their own account and forthe accounts of their customers, and such investment and securities activities may involve our securitiesand/or instruments. The underwriters and their respective affiliates may also make investmentrecommendations and/or publish or express independent research views in respect of such securities orinstruments and may at any time hold, or recommend to clients that they acquire, long and/or short positionsin such securities and instruments.

Selling Restrictions

European Economic Area

In relation to each member state of the European Economic Area which has implemented theProspectus Directive (each, a “Relevant Member State”), including each Relevant Member State that hasimplemented the 2010 PD Amending Directive with regard to persons to whom an offer of securities isaddressed and the denomination per unit of the offer of securities (each, an “Early Implementing MemberState”), with effect from and including the date on which the Prospectus Directive is implemented in thatRelevant Member State (the “Relevant Implementation Date”), no offer of shares will be made to the publicin that Relevant Member State (other than offers (the “Permitted Public Offers”) where a prospectus will bepublished in relation to the shares that has been approved by the competent authority in a Relevant MemberState or, where appropriate, approved in another Relevant Member State and notified to the competent

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authority in that Relevant Member State, all in accordance with the Prospectus Directive), except that witheffect from and including that Relevant Implementation Date, offers of shares may be made to the public inthat Relevant Member State at any time:

(a) to “qualified investors” as defined in the Prospectus Directive, including:

(i) (in the case of Relevant Member States other than Early Implementing MemberStates), legal entities which are authorized or regulated to operate in the financial markets or, ifnot so authorized or regulated, whose corporate purpose is solely to invest in securities, or anylegal entity which has two or more of (i) an average of at least 250 employees during the lastfinancial year; (ii) a total balance sheet of more than €43.0 million and (iii) an annual turnover ofmore than €50.0 million as shown in its last annual or consolidated accounts; or

(ii) (in the case of Early Implementing Member States), persons or entities that aredescribed in points (1) to (4) of Section I of Annex II to Directive 2004/39/EC, and those who aretreated on request as professional clients in accordance with Annex II to Directive 2004/39/EC, orrecognized as eligible counterparties in accordance with Article 24 of Directive 2004/39/ECunless they have requested that they be treated as non-professional clients;

(b) to fewer than 100 (or, in the case of Early Implementing Member States, 150) natural or legalpersons (other than “qualified investors” as defined in the Prospectus Directive), as permitted in theProspectus Directive, subject to obtaining the prior consent of the representatives for any such offer; or

(c) in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of shares shall result in a requirement for the publication of a prospectuspursuant to Article 3 of the Prospectus Directive or of a supplement to a prospectus pursuant to Article 16 ofthe Prospectus Directive.

Each person in a Relevant Member State (other than a Relevant Member State where there is aPermitted Public Offer) who initially acquires any shares or to whom any offer is made will be deemed tohave represented, acknowledged and agreed that (A) it is a “qualified investor”, and (B) in the case of anyshares acquired by it as a financial intermediary, as that term is used in Article 3(2) of the ProspectusDirective, (x) the shares acquired by it in the offering have not been acquired on behalf of, nor have theybeen acquired with a view to their offer or resale to, persons in any Relevant Member State other than“qualified investors” as defined in the Prospectus Directive, or in circumstances in which the prior consentof the Subscribers has been given to the offer or resale, or (y) where shares have been acquired by it onbehalf of persons in any Relevant Member State other than “qualified investors” as defined in theProspectus Directive, the offer of those shares to it is not treated under the Prospectus Directive as havingbeen made to such persons.

For the purpose of the above provisions, the expression “an offer to the public” in relation to anyshares in any Relevant Member State means the communication in any form and by any means of sufficientinformation on the terms of the offer of any shares to be offered so as to enable an investor to decide topurchase any shares, as the same may be varied in the Relevant Member State by any measureimplementing the Prospectus Directive in the Relevant Member State and the expression “ProspectusDirective” means Directive 2003/71 EC (including the 2010 PD Amending Directive, in the case of EarlyImplementing Member States) and includes any relevant implementing measure in each Relevant MemberState and the expression “2010 PD Amending Directive” means Directive 2010/73/EU.

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United Kingdom

This prospectus is only being distributed to, and is only directed at, persons in the United Kingdom thatare qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive (“QualifiedInvestors”) that are also (i) investment professionals falling within Article 19(5) of the Financial Servicesand Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”) or (ii) high net worth entities, andother persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order(all such persons together being referred to as “relevant persons”). This prospectus and its contents areconfidential and should not be distributed, published or reproduced (in whole or in part) or disclosed byrecipients to any other persons in the United Kingdom. Any person in the United Kingdom that is not arelevant person should not act or rely on this document or any of its contents.

Switzerland

The shares may not be publicly offered in Switzerland and will not be listed on the SIX SwissExchange (“SIX”) or on any other stock exchange or regulated trading facility in Switzerland. Thisdocument has been prepared without regard to the disclosure standards for issuance prospectuses under art.652a or art. 1156 of the Swiss Code of Obligations or the disclosure standards for listing prospectuses underart. 27 ff. of the SIX Listing Rules or the listing rules of any other stock exchange or regulated tradingfacility in Switzerland. Neither this document nor any other offering or marketing material relating to theshares or the offering may be publicly distributed or otherwise made publicly available in Switzerland.

Neither this document nor any other offering or marketing material relating to the offering, theCompany or the shares have been or will be filed with or approved by any Swiss regulatory authority. Inparticular, this document will not be filed with, and the offer of shares will not be supervised by, the SwissFinancial Market Supervisory Authority FINMA, and the offer of shares has not been and will not beauthorized under the Swiss Federal Act on Collective Investment Schemes (“CISA”). The investorprotection afforded to acquirers of interests in collective investment schemes under the CISA does notextend to acquirers of shares.

Chile

The shares of common stock will not be registered under Law 18,045, as amended, of Chile with theSuperintendencia de Valores y Seguros (Chilean Securities Commission), and accordingly, they may not beoffered to persons in Chile except in circumstances that do not constitute a public offering under Chileanlaw.

Australia

No prospectus or other disclosure document (as defined in the Corporations Act 2001 (Cth) ofAustralia (“Corporations Act”)) in relation to the shares being offered has been or will be lodged with theAustralian Securities & Investments Commission (“ASIC”). This document has not been lodged with ASICand is only directed to certain categories of exempt persons. Accordingly, if a potential investor receivesthis document in Australia:

(a) the potential investor must confirm and warrant that the potential investor is either:

(i) a “sophisticated investor” under section 708(8)(a) or (b) of the Corporations Act;

(ii) a “sophisticated investor” under section 708(8)(c) or (d) of the Corporations Act and that thepotential investor have provided an accountant’s certificate to us which complies with therequirements of section 708(8)(c)(i) or (ii) of the Corporations Act and related regulations beforethe offer has been made;

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(iii) a person associated with the company under section 708(12) of the Corporations Act; or

(iv) a “professional investor” within the meaning of section 708(11)(a) or (b) of the CorporationsAct, and to the extent that the potential investor is unable to confirm or warrant that the potentialinvestor is an exempt sophisticated investor, associated person or professional investor under theCorporations Act any offer made to the potential investor under this document is void andincapable of acceptance; and

(b) the potential investor warrants and agrees that the potential investor will not offer any of theshares for resale in Australia within 12 months of those shares being issued unless any such resaleoffer is exempt from the requirement to issue a disclosure document under section 708 of theCorporations Act.

Notice to Prospective Investors in Singapore

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore.Accordingly, this prospectus and any other document or material in connection with the offer or sale, orinvitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the sharesbe offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly orindirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of theSecurities and Futures Act, Chapter 289 of Singapore (the ‘‘SFA’’), (ii) to a relevant person, or any personpursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or(iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of theSFA, in each case subject to compliance with conditions set forth in the SFA.

Where the shares are subscribed or purchased under Section 275 by a relevant person which is:

• a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the solebusiness of which is to hold investments and the entire share capital of which is owned by one ormore individuals, each of whom is an accredited investor; or

• a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investmentsand each beneficiary of the trust is an individual who is an accredited investor, shares, debenturesand units of shares and debentures of that corporation or the beneficiaries’ rights and interest(howsoever described) in that trust shall not be transferred within six months after that corporationor that trust has acquired the shares under Section 275 of the SFA except:

• to an institutional investor (for corporations, under Section 274 of the SFA) or to a relevantperson defined in Section 275(2) of the SFA, or to any person pursuant to an offer that ismade on terms that such shares, debentures and units of shares and debentures of thatcorporation or such rights and interest in that trust are acquired at a consideration of not lessthan S$200,000 (or its equivalent in a foreign currency) for each transaction, whether suchamount is to be paid for in cash or by exchange of securities or other assets, and further forcorporations, in accordance with the conditions specified in Section 275 of the SFA;

• where no consideration is or will be given for the transfer; or

• where the transfer is by operation of law.

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LEGAL MATTERS

The validity of our common stock offered by this prospectus will be passed upon by Haynes andBoone, LLP, Dallas, Texas. Certain legal matters in connection with this offering will be passed upon forthe underwriters by Hunton & Williams LLP, Dallas, Texas.

EXPERTS

The audited consolidated financial statements of Matador Resources Company and its subsidiaries forthe years ended December 31, 2010 and 2009, and for each of the three years in the period endedDecember 31, 2010, included in this prospectus and elsewhere in the registration statement have been soincluded in reliance upon the report of Grant Thornton LLP, independent registered public accountants,upon the authority of said firm as experts in giving said report.

The estimates of proved reserves and future net revenue of Matador Resources Company atDecember 31, 2010 and 2009 and at September 30, 2011, have been audited by Netherland, Sewell &Associates, Inc., independent petroleum engineers, and such audit reports are included as exhibits to thisprospectus. The estimates of proved reserves and future net revenue of certain properties of MatadorResources Company at December 31, 2011 have been reviewed by Netherland, Sewell & Associates, Inc.,independent petroleum engineers, and such review report is included as an exhibit to this prospectus. Theestimates of proved reserves and future net revenue of Matador Resources Company at December 31, 2008,have been audited by LaRoche Petroleum Consultants, Ltd., independent petroleum engineers, and suchaudit reports are included as exhibits to this prospectus.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules andamendments thereto) under the Securities Act, with respect to the shares of our common stock offeredhereby. This prospectus does not contain all of the information set forth in the registration statement and theexhibits and schedules thereto. For further information with respect to us and the common stock offeredhereby, we refer you to the registration statement and the exhibits and schedules filed therewith. Statementscontained in this prospectus as to the contents of any contract, agreement or any other document aresummaries of the material terms of that contract, agreement or other document. With respect to each ofthese contracts, agreements or other documents filed as an exhibit to the registration statement, reference ismade to the exhibits for a more complete description of the matter involved. A copy of the registrationstatement, and the exhibits and schedules thereto, may be inspected without charge at the public referencefacilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materialsmay be obtained, upon payment of a duplicating fee, from the Public Reference Section of the SEC at100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further informationon the operation of the public reference facility. The SEC maintains a website that contains reports, proxyand information statements and other information regarding registrants that file electronically with the SEC.The address of the SEC’s website is http://www.sec.gov.

After we have completed this offering, we will file annual, quarterly and current reports, proxystatements and other information with the SEC. We expect to have an operational website concurrently withthe completion of this offering and we expect to make our periodic reports and other information filed with

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or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicableafter those reports and other information are electronically filed with or furnished to the SEC. Informationon our website or any other website is not incorporated by reference into this prospectus and does notconstitute a part of this prospectus. You may read and copy any reports, statements or other information onfile at the public reference rooms. You can also request copies of these documents, for a copying fee, bywriting to the SEC, or you can review these documents on the SEC’s website, as described above. Inaddition, we will provide electronic or paper copies of our filings free of charge upon request.

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Matador Resources Company and Subsidiaries

CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

Contents

Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-2

Audited Consolidated Financial Statements

Consolidated Balance Sheets at December 31, 2010 and 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-3Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and

2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-4Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2010, 2009

and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-5Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and

2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-6

Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-7

F-1

Report of Independent Registered Public Accounting Firm

Board of DirectorsMatador Resources Company

We have audited the accompanying consolidated balance sheets of Matador Resources Company (a Texascorporation) and subsidiaries (collectively, the “Company”) as of December 31, 2010 and 2009, and therelated consolidated statements of operations, shareholders’ equity, and cash flows for each of the threeyears in the period ended December 31, 2010. These financial statements are the responsibility of theCompany’s management. Our responsibility is to express an opinion on these financial statements based onour audits.

We conducted our audits in accordance with the standards of the Public Company Accounting OversightBoard (United States). Those standards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of material misstatement. The Company is notrequired to have, nor were we engaged to perform, an audit of its internal control over financial reporting.Our audit included consideration of internal control over financial reporting as a basis for designing auditprocedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on theeffectiveness of the Company’s internal control over financial reporting. Accordingly, we express no suchopinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosuresin the financial statements, assessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statement presentation. We believe that our auditsprovide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects,the financial position of Matador Resources Company and subsidiaries as of December 31, 2010 and 2009,and the results of their operations and their cash flows for each of the three years in the period endedDecember 31, 2010, in conformity with accounting principles generally accepted in the United States ofAmerica.

As discussed in Note B to the financial statements, the Company adopted new oil and gas reservesestimation and disclosure requirements as of December 31, 2009.

/s/ GRANT THORNTON LLP

Dallas, TexasAugust 12, 2011

F-2


CONSOLIDATED BALANCE SHEETS

December 31,

2010 2009

ASSETSCurrent assets

Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 21,059,519 $ 104,229,709Certificates of deposit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,349,313 15,675,346Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Oil and natural gas revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,514,122 5,750,957Joint interest billings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,042,999 2,234,330Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,091,372 3,277,535

Derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,144,411 1,005,685Lease and well equipment inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,423,197 1,818,514Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,876,358 1,329,559

Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42,501,291 135,321,635Property and equipment, at cost

Oil and natural gas properties, full-cost methodEvaluated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 255,408,993 192,249,326Unproved and unevaluated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 172,451,449 59,814,546

Other property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,035,010 12,474,215Less accumulated depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . (138,014,986) (122,459,957)

Net property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 303,880,466 142,078,130

Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 346,381,757 $ 277,399,765

LIABILITIES AND SHAREHOLDERS’ EQUITYCurrent liabilities

Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 12,166,938 $ 2,049,361Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,658,546 5,206,444Royalties payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 982,270 673,265Advances from joint interest owners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 722,843 450,000Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,473,619 339,471Dividends payable — Class B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68,713 68,713Other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23,577 80,904

Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30,096,506 8,868,158Long-term liabilities

Borrowings under Credit Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,000,000 –Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,695,017 2,551,637Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,432,638 1,635,003Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 280,453 23,577

Total long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34,408,108 4,210,217

Commitments and contingencies (Note 12)

Shareholders’ equityCommon stock — Class A, $0.01 par value, 80,000,000 shares authorized;

42,749,820 and 40,443,018 shares issued; and 41,570,645 and 40,375,348shares outstanding, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 427,498 404,430

Common stock — Class B, $0.01 par value, 2,000,000 shares authorized;1,030,700 shares issued and outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,307 10,307

Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 263,341,642 241,663,512Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28,862,518 22,760,408Treasury stock, at cost, 1,179,175 and 67,670 shares, respectively . . . . . . . . . . . . . . (10,764,822) (517,267)

Total shareholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 281,877,143 264,321,390

Total liabilities and shareholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . $ 346,381,757 $ 277,399,765

The accompanying notes are an integral part of these financial statements.

F-3


CONSOLIDATED STATEMENTS OF OPERATIONS

For the years ended December 31,

2010 2009 2008

RevenuesOil and natural gas revenues . . . . . . . . . . . . . . . . . . . . . . . . . . $34,041,607 $ 19,038,514 $ 30,645,065Realized gain (loss) on derivatives . . . . . . . . . . . . . . . . . . . . . 5,299,380 7,625,120 (1,325,970)Unrealized gain (loss) on derivatives . . . . . . . . . . . . . . . . . . . . 3,138,726 (2,374,638) 3,591,928

Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42,479,713 24,288,996 32,911,023Expenses

Production taxes and marketing . . . . . . . . . . . . . . . . . . . . . . . . 1,981,550 1,077,145 1,639,198Lease operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,284,362 4,725,022 4,666,591Depletion, depreciation and amortization . . . . . . . . . . . . . . . . 15,596,470 10,742,873 12,127,251Accretion of asset retirement obligations . . . . . . . . . . . . . . . . 154,756 137,347 91,157Full-cost ceiling impairment . . . . . . . . . . . . . . . . . . . . . . . . . . – 25,243,738 22,195,127General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,701,850 7,115,118 8,252,319

Total expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32,718,988 49,041,243 48,971,643

Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,760,725 (24,752,247) (16,060,620)

Other income (expense)Net (loss) gain on asset sales and inventory impairment . . . . . (223,690) (379,316) 136,977,430Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,235) – –Interest and other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 364,338 781,072 2,984,273

Total other income . . . . . . . . . . . . . . . . . . . . . . . . . . 137,413 401,756 139,961,703

Income (loss) before income taxes . . . . . . . . . 9,898,138 (24,350,491) 123,901,083Income tax provision (benefit)

Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,410,608) (2,324,338) 10,448,000Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,931,783 (7,600,811) 9,575,286

Total income tax provision (benefit) . . . . . . . . . . . . 3,521,175 (9,925,149) 20,023,286

Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . $ 6,376,963 $(14,425,342) $103,877,797

Earnings (loss) per common shareBasic

Class A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.15 $ (0.37) $ 2.50

Class B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.42 $ (0.10) $ 2.77

DilutedClass A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.15 $ (0.37) $ 2.46

Class B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.42 $ (0.10) $ 2.73

Weighted average common shares outstandingBasic

Class A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40,006,787 39,092,567 40,354,618Class B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,030,700 1,030,700 1,030,700

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,037,487 40,123,267 41,385,318

DilutedClass A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40,102,927 39,092,567 41,127,339Class B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,030,700 1,030,700 1,030,700

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,133,627 40,123,267 42,158,039


F-4


CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

For the years ended December 31, 2010, 2009 and 2008

Common stockAdditional

paid-incapital

Retainedearnings(deficit) Total

Class A Class B Treasury stock

Shares Amount Shares Amount Shares Amount

Balance at January 1, 2008 . . . 40,303,537 $403,035 1,030,700 $10,307 $236,728,584 $ (65,076,243) (18,948) $ (23,155) $172,042,528Additional cost to issue

equity . . . . . . . . . . . . . . . . . – – – – (40) – – – (40)Stock options granted . . . . . . . – – – – 528,480 – – – 528,480Stock options exercised . . . . . 235,500 2,355 – – 1,046,145 – – – 1,048,500Restricted stock issued . . . . . . 9,000 90 – – (90) – – – –Restricted stock vested . . . . . . – – – – 60,000 – – – 60,000Class B dividends declared . . . – – – – – (274,853) – – (274,853)Current period net income . . . – – – – – 103,877,797 – – 103,877,797Issuance of treasury stock . . . . – – – – 50,890 – 5,775 26,110 77,000Purchase of treasury stock . . . . – – – – – – (26,700) (354,500) (354,500)

Balance at December 31,2008 . . . . . . . . . . . . . . . . . . 40,548,037 405,480 1,030,700 10,307 238,413,969 38,526,701 (39,873) (351,545) 277,004,912

Issuance of Class A commonstock . . . . . . . . . . . . . . . . . . 4,974,194 49,742 – – 28,201,626 – – – 28,251,368

Additional cost to issueequity . . . . . . . . . . . . . . . . . – – – – (92,549) – – – (92,549)

Repurchase and retirement ofClass A common stock . . . . (5,422,713) (54,227) – – (26,686,133) (373,205) – – (27,113,565)

Stock options granted . . . . . . . – – – – 592,962 – – – 592,962Stock options exercised . . . . . 343,500 3,435 – – 1,278,065 – – – 1,281,500Restricted stock vested . . . . . . – – – – 33,750 – – – 33,750Class B dividends declared . . . – – – – – (274,853) – – (274,853)Current period net loss . . . . . . – – – – – (14,425,342) – – (14,425,342)Issuance of treasury stock . . . . – – – – (78,178) (692,893) 652,126 4,787,678 4,016,607Purchase of treasury stock . . . . – – – – – – (679,923) (4,953,400) (4,953,400)

Balance at December 31,2009 . . . . . . . . . . . . . . . . . . 40,443,018 404,430 1,030,700 10,307 241,663,512 22,760,408 (67,670) (517,267) 264,321,390

Issuance of Class A commonstock . . . . . . . . . . . . . . . . . . 1,879,427 18,794 – – 20,632,903 – – – 20,651,697

Additional cost to issueequity . . . . . . . . . . . . . . . . . – – – – (531,152) – – – (531,152)

Issuance of Class A commonstock to Board membersand advisors . . . . . . . . . . . . 20,000 200 – – 197,800 – – – 198,000

Stock options granted . . . . . . . – – – – 414,610 – – – 414,610Stock options exercised . . . . . 392,375 3,924 – – 1,974,451 – – – 1,978,375Stock options modified . . . . . . – – – – (1,086,271) – – – (1,086,271)Restricted stock issued . . . . . . 15,000 150 – – (150) – – – –Restricted stock vested . . . . . . – – – – 73,689 – – – 73,689Class B dividends declared . . . – – – – – (274,853) – – (274,853)Current period net income . . . – – – – – 6,376,963 – – 6,376,963Issuance of treasury stock . . . . – – – – 2,250 – 6,000 45,000 47,250Purchase of treasury stock . . . . – – – – – – (1,117,505) (10,292,555) (10,292,555)

Balance at December 31,2010 . . . . . . . . . . . . . . . . . . 42,749,820 $427,498 1,030,700 $10,307 $263,341,642 $ 28,862,518 (1,179,175) $(10,764,822) $281,877,143


F-5


CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31,

2010 2009 2008

Operating activitiesNet income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,376,963 $ (14,425,342) $ 103,877,797Adjustments to reconcile net income (loss) to net cash provided

by operating activitiesUnrealized (gain) loss on derivatives . . . . . . . . . . . . . . . . . (3,138,726) 2,374,638 (3,591,928)Depletion, depreciation and amortization . . . . . . . . . . . . . . 15,596,470 10,742,873 12,127,251Accretion of asset retirement obligations . . . . . . . . . . . . . . 154,756 137,347 91,157Full-cost ceiling impairment . . . . . . . . . . . . . . . . . . . . . . . . – 25,243,738 22,195,127Stock option and grant expense . . . . . . . . . . . . . . . . . . . . . . 824,048 622,337 605,480Restricted stock grants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73,689 33,750 60,000Deferred income tax provision . . . . . . . . . . . . . . . . . . . . . . 4,931,783 (7,600,811) 9,575,286Loss (gain) on asset sales and inventory impairment . . . . . 223,690 379,316 (136,977,430)Changes in operating assets and liabilities

Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . (385,671) 408,710 (7,136,855)Lease and well equipment inventory . . . . . . . . . . . . . . (8,078) (799,844) (607,460)Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (546,799) (153,206) (416,795)Accounts payable, accrued liabilities and other

liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,487,643 (15,463,066) 26,010,659Royalties payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 309,005 35,763 (60,100)Advances from joint interest owners . . . . . . . . . . . . . . 272,843 450,000 –State income tax payable . . . . . . . . . . . . . . . . . . . . . . . – (48,000) 48,000Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . 101,423 (147,155) 50,608

Net cash provided by operating activities . . . . . . 27,273,039 1,791,048 25,850,797Investing activities

Proceeds from sale of oil and natural gas properties . . . . . . . . . . – 28,732 185,468,400Oil and natural gas properties capital expenditures . . . . . . . . . . . (159,050,066) (54,243,838) (104,118,639)Expenditures for other property and equipment . . . . . . . . . . . . . (1,609,882) (306,642) (3,011,869)Purchases of certificates of deposit . . . . . . . . . . . . . . . . . . . . . . . (3,739,000) (15,500,424) (20,781,934)Sales of certificates of deposit . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,065,033 20,607,012 –Sales of short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . – – 57,925,000

Net cash (used in) provided by investingactivities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (147,333,915) (49,415,160) 115,480,958

Financing activitiesBorrowings under Credit Agreement . . . . . . . . . . . . . . . . . . . . . 25,000,000 – –Proceeds from issuance of common stock, net of cost to issue

equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,479,719 28,158,819 (40)Proceeds from stock options exercised . . . . . . . . . . . . . . . . . . . . 1,978,375 1,281,500 1,048,500Payment of dividends — Class B . . . . . . . . . . . . . . . . . . . . . . . . (274,853) (274,853) (274,853)Repurchase and retirement of Class A common stock . . . . . . . . – (27,113,565) –Issuance of treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 3,987,231 –Purchase of treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (10,292,555) (4,953,400) (354,500)

Net cash provided by financing activities . . . . . . 36,890,686 1,085,732 419,107

(Decrease) increase in cash and cash equivalents . . . . . . . . . . . . . . . . $ (83,170,190) $ (46,538,380) $ 141,750,862Cash and cash equivalents at beginning of year . . . . . . . . . . . . . . . . . 104,229,709 150,768,089 9,017,227

Cash and cash equivalents at end of year . . . . . . . . . . . . . . . . . . . . . . $ 21,059,519 $104,229,709 $ 150,768,089

Supplemental disclosures of cash flow information (Note 14)


F-6


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010, 2009 and 2008

NOTE 1 — NATURE OF OPERATIONS

Matador Resources Company (“Matador” or “Company”) is an independent energy company engagedin the exploration, development, acquisition and production of oil and natural gas resources in the UnitedStates, with a particular emphasis on oil and natural gas shale plays and other unconventional resources.Matador’s current operations are located primarily in the Haynesville shale play in north Louisiana and eastTexas and the Eagle Ford shale play in south Texas; these plays are key elements of the Company’s growthstrategy. In addition to these primary operating areas, Matador has significant acreage positions in southeastNew Mexico and west Texas and in southwest Wyoming and adjacent areas in Utah and Idaho where theCompany continues to identify new oil and natural gas prospects.

Matador was founded on July 3, 2003 as a Texas corporation. Two equity investors contributed$6,000,000 for 900,000 shares of Matador Class B common stock on July 31, 2003, providing theCompany’s initial capitalization. At December 31, 2010, Matador has issued 42,749,820 shares of Class Acommon stock and 1,030,700 shares of Class B common stock to qualified investors, which has resulted innet proceeds of $261,233,910. Matador holds the primary assets of the Company while its wholly ownedsubsidiary, Matador Production Company, serves as the operating entity.

In February 2006, the Company formed a wholly owned subsidiary, Longwood Gathering andDisposal Systems GP, Inc., for the business purpose of serving as the general partner of LongwoodGathering and Disposal Systems, LP. Longwood Gathering and Disposal Systems, LP was formed for thebusiness purpose of owning and operating a majority of the pipeline systems and salt water disposal wellsused in the Company’s operations, as well as to transport third-party natural gas.

In October 2006, the Company formed a wholly owned subsidiary, MRC Permian Company, via amerger, for the business purpose of establishing and conducting oil and natural gas exploration anddevelopment activities in southeast New Mexico.

In January 2009, the Company formed a wholly owned subsidiary, MRC Rockies Company, for thebusiness purpose of establishing and conducting oil and natural gas exploration and development activitiesin the Rocky Mountains and specifically in the states of Wyoming, Utah and Idaho.

On November 22, 2010, Matador Resources Company formed a wholly-owned subsidiary, MatadorHoldco, Inc. Pursuant to the terms of the corporate reorganization that was completed on August 9, 2011,Matador Resources Company changed its corporate name to MRC Energy Company and Matador Holdco,Inc. changed its corporate name to Matador Resources Company. As a part of this reorganization, MRCEnergy Company became a wholly owned subsidiary of Matador Resources Company.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated financial statements include the accounts of Matador Resources Company and itsfour wholly owned subsidiaries, Matador Production Company, Longwood Gathering and Disposal Systems

F-7


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED

December 31, 2010, 2009 and 2008

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

GP, Inc., MRC Permian Company and MRC Rockies Company, as well as the accounts of LongwoodGathering and Disposal Systems, LP. These consolidated financial statements have been prepared inaccordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”).The Company’s operations are conducted in the one segment generally referred to as the oil and natural gasexploration and production industry. All significant intercompany balances and transactions have beeneliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to makeestimates and assumptions that affect the amounts reported in the financial statements and accompanyingnotes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at thedate of the financial statements and the reported amounts of revenues and expenses during the reportingperiod. While the Company believes its estimates are reasonable, changes in facts and assumptions or thediscovery of new information may result in revised estimates. Actual results could differ from theseestimates.

The Company’s consolidated financial statements are based on a number of significant estimates,including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation ofderivative instruments and oil and natural gas reserves. The estimates of oil and natural gas reservesquantities and future net cash flows are the basis for the calculations of depletion and impairment of oil andnatural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. TheCompany’s oil and natural gas reserves estimates, which are inherently imprecise and based upon manyfactors that are beyond the Company’s control, including oil and natural gas prices, are prepared by theCompany’s engineering staff in accordance with guidelines established by the Securities and ExchangeCommission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines andgenerally accepted petroleum engineering and evaluation principles by independent outside petroleumengineers.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of thirty (30) days orless as cash equivalents, and cash equivalents are recorded at market. Except for small cash balances held inthe Company’s operating accounts to conduct its ongoing business, the remainder of the Company’s cashequivalents at December 31, 2010 and 2009 was held in money market accounts composed of United StatesTreasury securities offering daily liquidity.

Certificates of Deposit

Certificates of deposit (“CDs”) are highly liquid, short-term investments with an original maturity ofmore than 30 days but not more than one year. Each CD is recorded at market and is fully insured by theFederal Deposit Insurance Corporation.

F-8



December 31, 2010, 2009 and 2008


Accounts Receivable

The Company sells its operated oil and natural gas production to various purchasers (see Note 13). Dueto the nature of the markets for oil and natural gas, the Company does not believe that the loss of any onepurchaser would significantly impact operations. In addition, the Company may participate with industrypartners in the drilling, completion and operation of oil and natural gas wells. Substantially all of theCompany’s accounts receivable are due from either purchasers of oil and natural gas or participants in oiland natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30to 45 days of the production or billing date and are stated at amounts due from purchasers and industrypartners.

The Company reviews its need for an allowance for doubtful accounts on a periodic basis, anddetermines the allowance, if any, by considering the length of time past due, previous loss history, future netrevenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company andthe debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtfulaccounts related to its accounts receivable for any reporting period presented.

During 2008, the Company wrote off a portion of its oil sales receivable totaling $223,770 from certainnon-operated properties in Lea County, New Mexico as a result of SemCrude, L.P. and several of itssubsidiaries and related entities filing for a Petition of Relief under Chapter 11 of the United StatesBankruptcy Code in the United States Bankruptcy Court for the District of Delaware. The operators of theseproperties filed claims in the bankruptcy proceeding on behalf of their operating partners (includingMatador), and in 2010, the Company received a partial recovery of $124,635 resulting from these claims.The Company did not write off any receivables in 2010 or 2009. When necessary, the Company accountsfor a write off by recording the loss as an offset against accounts receivable once the specific account hasbeen determined to be uncollectible.

Lease and Well Equipment Inventory

Lease and well equipment inventory is stated at the lower of cost or market and consists entirely ofequipment scheduled for use in future well operations or equipment held for sale.


The Company uses the full-cost method of accounting for its investments in oil and natural gasproperties. Under this method of accounting, all costs associated with the acquisition, exploration anddevelopment of oil and natural gas properties and reserves, including unproved and unevaluated propertycosts, are capitalized as incurred and accumulated in a single cost center representing the Company’sactivities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs,geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling bothproductive and non-productive wells, capitalized interest on qualifying projects and general andadministrative expenses directly related to exploration, and development activities, but do not include anycosts related to production, selling or general corporate administrative activities. The Company capitalized$1,604,682, $1,642,868 and $1,679,992 of its general and administrative costs in 2010, 2009 and 2008,respectively.

F-9



December 31, 2010, 2009 and 2008


The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costsless related deferred income taxes or the cost center ceiling, with any excess above the cost center ceilingcharged to operations as a full-cost ceiling impairment. The cost center ceiling is defined as the sum of(a) the present value discounted at 10 percent of future net revenues of proved oil and natural gas reserves,plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost orestimated fair value of unproved and unevaluated properties included in the costs being amortized, if any,less (d) income tax effects related to differences between the book and tax basis of the properties involved.Future net revenues from proved non-producing and proved undeveloped reserves are reduced by theestimated costs for developing these reserves. The fair value of the Company’s derivative instruments is notincluded in the ceiling test computation as the Company does not designate these instruments as hedgeinstruments for accounting purposes.

The estimated present value of after-tax future net cash flows from proved oil and natural gas reservesis highly dependent on the commodity prices used in these estimates. These estimates are determined inaccordance with guidelines established by the SEC for estimating and reporting oil and natural gas reserves.Under these guidelines, oil and natural gas reserves are estimated using then-current operating andeconomic conditions, with no provision for price and cost escalations in future periods except by contractualarrangements. In January 2009, the SEC issued The Modernization of Oil and Gas Reporting, Final Ruleand in January 2010, the Financial Accounting Standards Board (“FASB”) amended Topic 932, ExtractiveActivities — Oil and Gas to align with this rule. As a result, beginning December 31, 2009, the commodityprices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages offirst-day-of-the-month oil and natural gas prices for the previous 12-month period. For the period Januarythrough December 2010, these average oil and natural gas prices were $75.96 per barrel and $4.376 perMMBtu (million British thermal units), respectively. For the period January through December 2009, theseaverage oil and natural gas prices were $57.65 per barrel and $3.866 per MMBtu, respectively. Inestimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, theaverage oil prices were further adjusted by property for quality, transportation fees and regional pricedifferentials, and the average natural gas prices were further adjusted by property for energy content,transportation fees and regional price differentials.

Using the average commodity prices, as further adjusted, for 2010 to determine the Company’sestimated proved oil and natural gas reserves at December 31, 2010, the Company’s net capitalized costsless related deferred income taxes did not exceed the full-cost ceiling. As a result, the Company recorded noimpairment to its net capitalized costs and no corresponding charge to its consolidated statement ofoperations for 2010. Changes in oil and natural gas production rates, reserves estimates, future developmentcosts, and other factors will determine the Company’s actual ceiling test computation and impairmentanalyses in future periods.

Using the average commodity prices, as further adjusted, for 2009 to determine the Company’sestimated proved oil and natural gas reserves at December 31, 2009, the Company’s net capitalized costsless related deferred income taxes exceeded the full-cost ceiling by $16,267,822. The Company recorded animpairment charge of $25,243,738 to its net capitalized costs and a deferred income tax credit of $8,975,916

F-10



December 31, 2010, 2009 and 2008


related to the full-cost ceiling limitation for 2009. Corresponding charges were also recorded to theCompany’s consolidated statement of operations for 2009.

Prior to 2009, SEC guidelines for estimating and reporting oil and natural gas reserves required usingcommodity prices at the last day of the year. For 2008, these year-end oil and natural gas prices were $41.00 perbarrel and $5.71 per MMBtu, respectively. The average oil price was further adjusted by property for quality,transportation fees and regional price differentials, and the average natural gas price was further adjusted byproperty for energy content, transportation fees and regional price differentials. Using these commodity prices, asfurther adjusted, for 2008 to determine the Company’s estimated proved oil and natural gas reserves atDecember 31, 2008, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $14,303,206. The Company recorded an impairment charge of $22,195,127 to its net capitalizedcosts and a deferred income tax credit of $7,891,921 related to the full-cost ceiling limitation for 2008.Corresponding charges were also recorded to the Company’s consolidated statement of operations for 2008.

As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the netcarrying value of the Company’s assets on its balance sheet, as well as the corresponding shareholders’equity, but it has no impact on the Company’s net cash flows as reported.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production methodbased upon production and estimates of proved reserves quantities. Unproved and unevaluated propertycosts are excluded from the amortization base used to determine depletion. Unproved and unevaluatedproperties are assessed for possible impairment on a periodic basis based upon changes in operating oreconomic conditions. This assessment includes consideration of the following factors, among others: theassignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term,and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties areimmediately included in the amortization base. Exploratory dry holes are included in the amortization baseimmediately upon determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with nogain or loss recognized, unless such adjustments would significantly alter the relationship between netcapitalized costs and proved reserves of oil and natural gas. All costs related to production activities andmaintenance and repairs are expensed as incurred. Significant workovers that increase the properties’reserves are capitalized.

Other property and equipment are stated at cost. Computer equipment, furniture, software and otherequipment are depreciated over their useful life (5 to 7 years) using the straight-line method. Supportequipment and facilities include the pipelines and salt water disposal systems owned by LongwoodGathering and Disposal Systems, LP and are depreciated over a 30-year useful life using the straight-line,mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lifeor the term of the lease.

F-11



December 31, 2010, 2009 and 2008


Asset Retirement Obligations

The Company recognizes the fair value of an asset retirement obligation in the period in which it isincurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as aliability at its estimated present value, with an offsetting increase recognized in oil and natural gasproperties or support equipment and facilities on the balance sheet. Periodic accretion of the discountedvalue of the estimated liability is recorded as an expense in the consolidated statement of operations. Ingeneral, the Company’s future asset retirement obligations relate to future costs associated with pluggingand abandonment of its oil and natural gas wells, removal of equipment and facilities from leased acreageand returning such land to its original condition. The amounts recognized are based on numerous estimatesand assumptions, including future retirement costs, future recoverable quantities of oil and natural gas,future inflation rates and the credit-adjusted risk-free interest rate. Revisions to the liability can occur due tochanges in its estimate or if federal or state regulators enact new plugging and abandonment requirements.At the time of actual plugging and abandonment of its oil and natural gas wells, the Company includes anygain or loss associated with the operation in the amortization base to the extent that the actual costs aredifferent from the estimated liability.

Derivative Financial Instruments

From time to time, the Company uses derivative financial instruments to hedge its exposure tocommodity price risk associated with natural gas prices. These instruments consist of put and call options inthe form of costless collars. The Company’s derivative financial instruments are recorded on the balancesheet as either an asset or a liability measured at fair value. The Company has elected not to apply hedgeaccounting for its existing derivative financial instruments, and as a result, the Company recognizes thechange in derivative fair value between reporting periods currently in its consolidated statement ofoperations (see Note 10). The fair value of the Company’s derivative financial instruments is determinedbased on its counterparty’s valuation model, which the Company verifies for its reasonableness with anindependent third-party valuation using observable, market-corroborated inputs.

Revenue Recognition

The Company follows the sales method of accounting for its oil and natural gas revenue, whereby itrecognizes revenue, net of royalties, on all oil or natural gas sold to purchasers regardless of whether the salesare proportionate to its ownership in the property. Under this method, revenue is recognized at the time oil andnatural gas are produced and sold, and the Company accrues for revenue earned but not yet received.

Stock-Based Compensation

Non-qualified stock option expense is recognized in the Company’s consolidated statement ofoperations on the date of grant. Incentive stock options vest over four years, and the associatedcompensation expense is recognized on a straight-line basis over the vesting period. Prior to November 22,2010, all of the Company’s outstanding stock options were classified as equity instruments, with all stock-based compensation expense measured on the date of grant and recognized over the vesting period, if any.

F-12



December 31, 2010, 2009 and 2008


On November 22, 2010, the Company changed its method of accounting for outstanding stock options,reclassifying all outstanding stock options from equity to liability instruments. This change was made as aresult of the Company purchasing shares from certain of its employees to assist them in the exercise ofoutstanding options of the Company’s Class A common stock. As a result, at December 31, 2010, theCompany measured and recognized the fair value of the liability associated with its outstanding stockoptions using an estimated fair value for the Company’s Class A common stock.

The Company’s consolidated statements of operations for the years ended December 31, 2010, 2009and 2008 include a stock-based compensation (non-cash) expense of $897,737, $656,087 and $665,480,respectively. This stock-based compensation expense includes common stock and treasury stock issuancestotaling $245,250, $29,375 and $77,000 in 2010, 2009 and 2008, respectively, paid to members of theBoard of Directors and advisors as compensation for their services to the Company.

Income Taxes

The Company accounts for income taxes using the asset and liability approach for financial accountingand reporting. The Company evaluates the probability of realizing the future benefits of its deferred taxassets and provides a valuation allowance for the portion of any deferred tax assets where the likelihood ofrealizing an income tax benefit in the future does not meet the more likely than not criteria for recognition.

At January 1, 2008, the Company adopted the accounting guidance related to accounting foruncertainty in income taxes which provides for the financial statement benefit of a tax position as beingrecognized only after determining that the relevant tax authority would more likely than not sustain theposition following an audit. For tax positions meeting the more-likely-than-not threshold, the amountrecognized in the financial statements is the benefit that has a greater than 50 percent likelihood of beingrealized upon ultimate settlement with the relevant tax authority. Following adoption, the Companyevaluated all tax positions for which the statute of limitations remained open, and management believes thatthe material positions taken by the Company would more likely than not be sustained by examination.Therefore, at December 31, 2010, the Company had not established any reserves for, nor recorded anyunrecognized tax benefits related to, uncertain tax positions.

When necessary, the Company would include interest assessed by taxing authorities in “Interestexpense” and penalties related to income taxes in “Other expense” on its consolidated statements ofoperations. At December 31, 2010, 2009 and 2008, the Company did not record any interest or penaltiesrelated to income tax.

Earnings Per Common Share

The Company reports basic earnings per common share, which excludes the effect of potentiallydilutive securities, and diluted earnings per common shares, which includes the effect of all potentiallydilutive securities, unless their impact is anti-dilutive. The Company has issued two classes of commonstock, Class A and Class B. The holders of the Class B shares are entitled to be paid cumulative dividends ata per share rate of $0.26-2/3 annually out of funds legally available for the payment of dividends. These

F-13



December 31, 2010, 2009 and 2008


dividends are accrued and paid quarterly. Dividends declared during 2010, 2009 and 2008 totaled $274,853in each year. The holders of the Class B shares are also entitled to share on an equivalent basis in anydividends paid to holders of the Class A shares when and as declared by the Board of Directors. AtDecember 31, 2010, the Company had not paid any dividends to holders of the Class A shares.

The following are reconciliations of the numerators and denominators used to compute the Company’sbasic and diluted distributed and undistributed earnings per common share as reported for the years endedDecember 31, 2010, 2009 and 2008.

Year ended December 31,

2010 2009 2008

Net income (loss) — numeratorNet income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,376,963 $(14,425,342) $103,877,797Less dividends to Class B shareholders — distributed

earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (274,853) (274,853) (274,853)

Undistributed earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,102,110 $(14,700,195) $103,602,944

Weighted average common shares outstanding — denominatorBasic

Class A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40,006,787 39,092,567 40,354,618Class B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,030,700 1,030,700 1,030,700

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,037,487 40,123,267 41,385,318

DilutedClass A

Weighted average common shares outstanding for basicearnings per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40,006,787 39,092,567 40,354,618

Dilutive effect of options . . . . . . . . . . . . . . . . . . . . . . . . . . 96,140 – 772,721

Class A weighted average common shares outstanding— diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,102,927 39,092,567 41,127,339

Class BWeighted average common shares outstanding — no

associated dilutive shares . . . . . . . . . . . . . . . . . . . . . . . 1,030,700 1,030,700 1,030,700

Total diluted weighted average common sharesoutstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,133,627 40,123,267 42,158,039

F-14



December 31, 2010, 2009 and 2008



2010 2009 2008


Class ADistributed earnings . . . . . . . . . . . . . . . . . . . $ – $ – $ –Undistributed earnings (loss) . . . . . . . . . . . . $0.15 $(0.37) $2.50

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . $0.15 $(0.37) $2.50

Class BDistributed earnings . . . . . . . . . . . . . . . . . . . $0.27 $ 0.27 $0.27Undistributed earnings (loss) . . . . . . . . . . . . $0.15 $(0.37) $2.50

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . $0.42 $(0.10) $2.77

DilutedClass A

Distributed earnings . . . . . . . . . . . . . . . . . . . $ – $ – $ –Undistributed earnings (loss) . . . . . . . . . . . . $0.15 $(0.37) $2.46

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . $0.15 $(0.37) $2.46

Class BDistributed earnings . . . . . . . . . . . . . . . . . . . $0.27 $ 0.27 $0.27Undistributed earnings (loss) . . . . . . . . . . . . $0.15 $(0.37) $2.46

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . $0.42 $(0.10) $2.73

A total of 1,551,750 options to purchase shares of the Company’s Class A common stock was excludedfrom the calculations above for the year ended December 31, 2009, because their effects were anti-dilutive.

Fair Value Measurements

The Company measures and reports certain assets and liabilities on a fair value basis. Fair value is theprice that would be received to sell an asset or paid to transfer a liability in an orderly transaction betweenmarket participants at the measurement date (exit price). The Company follows FASB guidance establishinga fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value.

The carrying amounts reported on the balance sheet for cash and cash equivalents, certificates ofdeposit, accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable,advances from joint interest owners, dividends payable and other liabilities approximate their fair values,due to the short-term maturity of these instruments.

At December 31, 2010, the carrying value of $25,000,000 for the Company’s borrowings under its$150,000,000 senior secured revolving credit agreement (“Credit Agreement”) on the consolidated balance

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December 31, 2010, 2009 and 2008


sheet is approximately fair value as it is subject to short-term floating interest rates that approximate therates available to the Company at the time.

Credit Risk

The Company uses derivative financial instruments to hedge its exposure to natural gas price volatility.These transactions expose the Company to potential credit risk from its single counterparty. Accountsreceivable constitute the principal component of additional credit risk to which the Company may beexposed. The Company believes that any credit risk posed is insignificant and is offset by the creditworthiness of its customer base and industry partners.

Risks and Uncertainties

As an oil and natural gas exploration and production company focused on finding and developing itsown prospects and reserves, the Company’s success is highly dependent on the results of its explorationprogram. Exploration activities involve numerous risks, including the risk that no commercially productiveoil or natural gas reserves will be discovered. In addition, there are uncertainties as to the future costs ortiming of drilling, completing and producing wells. Poor results from the Company’s exploration activitiescould limit the Company’s ability to replace and grow reserves and materially and adversely affect theCompany’s financial position, results of operations and cash flows.

The Company does not operate properties constituting a significant portion of its oil and natural gasreserves. As a result of the Company’s sale of certain assets to Chesapeake Louisiana, L.P. (“Chesapeake”)in 2008, the Company does not operate its most significant natural gas asset, that being the deep rights toexplore for and develop the Haynesville shale formation (underlying its existing Cotton Valley production)on the Company’s Elm Grove/Caspiana leasehold in north Louisiana. Although the Company has reservedthe right to participate for a proportionately reduced 25% working interest in all wells that Chesapeake drillsor participates in to develop the Haynesville formation on this acreage, and although the Company has theright to propose the drilling of Haynesville wells on these properties, the Company may have limitedinfluence on when, how and at what pace these properties are developed. This could impact the Company’sability to replace and grow reserves and materially and adversely affect the Company’s financial position,results of operations and cash flows. In addition, in 2009 and 2010, the Company acquired othernon-operated acreage positions in north Louisiana that it believes to be prospective for the Haynesvilleshale. The Company has, or will have, small, non-operated working interests in the Haynesville unitsincluding these properties, and as a result, the Company will have limited influence on when, how and atwhat pace these properties are developed.

Estimating oil and natural gas reserves is complex and is not exact because of the numerousuncertainties inherent in the process. The process relies on interpretations of available geological,geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both thedata and the associated interpretations of that data can vary. The process also requires certain economicassumptions, including, but not limited to, oil and natural gas prices, drilling and operating expenses, capital

F-16



December 31, 2010, 2009 and 2008


expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, developmentexpenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary fromthe Company’s estimates. Any significant variance could materially and adversely affect the Company’sfuture reserves estimates, financial position, results of operations and cash flows.

Historically, the market for oil and natural gas has experienced significant price fluctuations, and thishas been particularly evident in recent years. Oil and natural gas prices are impacted by supply and demand,both domestic and international, seasonal variations caused by changing weather conditions, politicalconditions, governmental regulations, the availability, proximity and capacity of gathering systems fornatural gas and numerous other factors. Increases or decreases in prices received could have a significantand material impact on the Company’s future reserves estimates, financial position, results of operations andcash flows.

To mitigate its exposure to fluctuations in natural gas prices, the Company, from time to time, entersinto hedging arrangements, typically using put and call options in the form of “costless collars,” withrespect to a portion of its natural gas production. Decisions as to whether and at what production volumes tohedge are difficult and depend on market conditions and the Company’s forecast of future production andcommodity prices, and the Company may not always employ the optimal hedging strategy. The Companycurrently has no hedging contracts in place with regard to any of its oil production and no hedging contractsin place beyond 2011 with regard to any of its natural gas production.

The federal, state and local governments in the areas in which the Company operates or has assetsimpose taxes on the oil and gas products sold, and sales and use taxes are charged on significant portions ofthe Company’s drilling, completion and operating costs. Historically, there has been a significant amount ofdiscussion by legislators and presidential administrations concerning a variety of energy tax proposals. U.S.President Obama has proposed sweeping changes in federal laws on the income taxation of oil and gasexploration and production companies. President Obama has proposed to eliminate allowing U.S. oil andgas companies to deduct intangible well costs as incurred and percentage depletion, among other proposals.Many states have raised state taxes on energy sources, and additional increases may occur. Changes to taxlaws could materially and adversely affect the Company’s future financial position, results of operations andcash flows.


Subsequent Events. The Company incorporates the accounting and disclosure requirements forsubsequent events in its financial statements. In accordance with U.S. GAAP, new terminology wasintroduced recently which defines the date through which management must evaluate subsequent events andlists the circumstances under which an entity must recognize and disclose events or transactions occurringafter the balance sheet date. The Company adopted this guidance at December 31, 2009.

Oil and Natural Gas Reserves Reporting Requirements. In January 2009, the SEC issued TheModernization of Oil and Gas Reporting, Final Rule. In January 2010, the FASB amended Topic 932,Extractive Activities — Oil and Gas to align with this rule. The changes are designed to modernize and

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December 31, 2010, 2009 and 2008


update the oil and gas disclosure requirements to align them with current practices and changes intechnology. The new rules made a number of important changes including the following: (i) expanded thedefinition of oil and gas producing activities to include the extraction of saleable hydrocarbons from oilsands, shale, coalbeds, or other nonrenewable natural resources, (ii) amended the required price forestimating economic quantities for year-end reserves reporting to be the unweighted, arithmetic average ofthe first-day-of-the-month price for each month within the previous 12-month period, rather than theyear-end price, and (iii) permitted proved reserves to be claimed beyond those development spacing areasthat are immediately adjacent to developed spacing areas if it can be established with reasonable certaintythat these reserves are economically producible. At December 31, 2009, the Company adopted theprovisions of the new rule, and the Company has applied this new guidance for the reserves estimates atDecember 31, 2010 and 2009 included herein.

Derivative Financial Instruments. At December 31, 2008, the Company adopted new guidance toprovide qualitative disclosures about its objectives and strategies for using derivative financial instrumentsand to provide a tabular presentation of quantitative information for derivatives designated as hedges,hedged items and other derivatives. This new guidance was effective for annual periods beginning afterNovember 15, 2008. As its only requirement is to enhance disclosures, the new guidance had no materialimpact on the Company’s consolidated financial statements.

Fair Value. In May 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-04,Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP andIFRS (“ASU 2011-04”). ASU 2011-04 amends Accounting Standards Codification (“ASC”) 820, FairValue Measurements (“ASC 820”), providing a consistent definition and measurement of fair value, as wellas similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards.ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fairvalue measurements and expands the ASC 820 disclosure requirements, particularly for Level 3 fair valuemeasurements. The adoption of ASU 2011-04 is not expected to have a material effect on the Company’sconsolidated financial statements, but may require certain additional disclosures. The amendments in ASU2011-04 are to be applied prospectively. For public entities, the amendments are effective during interimand annual periods beginning after December 15, 2011.

In January 2010, the FASB issued authoritative guidance to update certain disclosure requirements andadded two new disclosure requirements to fair value measurements. The guidance requires a grosspresentation of activities within the Level 3 roll forward and adds a new requirement to disclose details ofsignificant transfers in and out of Level 1 and 2 measurements and the reasons for the transfers. The newdisclosures are required for all companies that are required to provide disclosures about recurring andnon-recurring fair value measurements and are effective for the first interim or annual reporting periodbeginning after December 15, 2009, except for the gross presentation of Level 3 roll forward information,which is required for annual reporting periods beginning after December 15, 2010 and for interim reportingperiods within those years. The Company adopted the first portion of this guidance beginning January 1,2010. The Company does not expect the adoption of this new guidance to have a significant impact on theCompany’s financial position, results of operations or cash flows.

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December 31, 2010, 2009 and 2008


In September 2006, the FASB issued authoritative guidance for using fair value to measure assets andliabilities. The guidance applies whenever other standards require or permit assets or liabilities to bemeasured at fair value, but it did not expand the use of fair value in any new circumstances. In February2009, the FASB delayed the effective date by one year for non-financial assets and liabilities. The Companyadopted this guidance effective January 1, 2008 and delayed guidance relating to non-financial assets andliabilities until January 1, 2009. The adoption of this guidance did not have a significant impact on theCompany’s financial position, results of operations or cash flows.

In February 2007, the Company adopted the accounting guidance permitting entities to choose tomeasure certain financial instruments and other items at fair value. The objective is to improve financialreporting by providing entities with the opportunity to mitigate volatility in reported earnings caused bymeasuring related assets and liabilities differently without having to apply complex hedge accountingprovisions. Unrealized gains and losses on any items for which the fair value measurement option is electedare to be reported in the consolidated statement of operations. The Company adopted this guidance atJanuary 1, 2008. The Company elected not to measure any eligible items using the fair value option inaccordance with this guidance, and therefore, it did not have an impact on the Company’s financial position,results of operations or cash flows.

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December 31, 2010, 2009 and 2008

NOTE 3 — PROPERTY AND EQUIPMENT

The following table presents a summary of the Company’s property and equipment balances atDecember 31, 2010 and 2009.

December 31,

2010 2009

Oil and natural gas propertiesEvaluated (subject to amortization) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 255,408,993 $ 192,249,326Unproved and unevaluated (not subject to amortization)

Incurred in 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121,950,288 –Incurred in 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,267,810 21,835,909Incurred in 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26,155,365 26,526,395Incurred in 2007 and prior . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,077,986 11,452,242

Total unproved and unevaluated . . . . . . . . . . . . . . . . . . . . . . . . . . . 172,451,449 59,814,546

Total oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . 427,860,442 252,063,872Accumulated depletion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (134,700,857) (119,643,416)

Net oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . 293,159,585 132,420,456Other property and equipment

Computer equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 685,493 601,289Furniture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 416,095 407,723Software . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,000,558 953,596Other equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111,450 90,671Leasehold improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65,899 65,899Support equipment and facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,755,515 10,355,037

Total other property and equipment . . . . . . . . . . . . . . . . . . . . . . . 14,035,010 12,474,215Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,314,129) (2,816,541)

Net other property and equipment . . . . . . . . . . . . . . . . . . . . . . 10,720,881 9,657,674

Net property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . $ 303,880,466 $ 142,078,130

The following table provides a breakdown of the Company’s unproved and unevaluated property costsnot subject to amortization at December 31, 2010 and the year in which these costs were incurred.

Description 2010 2009 20082007 and

prior Total

Costs incurred forProperty acquisition . . . . . . . . . $ 86,043,632 $14,267,810 $26,155,365 $10,077,986 $136,544,793Exploration wells . . . . . . . . . . . 35,906,656 – – – 35,906,656Development wells . . . . . . . . . – – – – –Capitalized interest . . . . . . . . . – – – – –

Total . . . . . . . . . . . . . . . . . $121,950,288 $14,267,810 $26,155,365 $10,077,986 $172,451,449

F-20



December 31, 2010, 2009 and 2008

NOTE 3 — PROPERTY AND EQUIPMENT — Continued

Property acquisition costs primarily include leasehold costs paid to secure oil and gas mineral leases,but may also include broker and legal expenses, geological and geophysical expenses and capitalizedinternal costs associated with defining oil and natural gas prospects on these properties. Property acquisitioncosts are transferred into the amortization base on an ongoing basis as these properties are evaluated andproved reserves are established or impairment is determined. Unproved and undeveloped properties areassessed for possible impairment on a periodic basis based upon changes in operating or economicconditions.

Property acquisition costs incurred in 2010 were primarily related to the Company’s leasing activitiesin the Eagle Ford shale play in south Texas and the Haynesville shale play in north Louisiana. At December31, 2010, the Company had only just begun drilling wells on its Eagle Ford shale acreage. Portions of thesecosts will be transferred to the amortization base periodically as the Company drills wells and assignsproved reserves to these properties or determines that certain portions of this acreage, if any, cannot beassigned proved reserves. The same is true for the Haynesville acreage acquired in 2010, although someportions of the Company’s Haynesville acreage acquired in 2010 have already been assigned provedreserves and the corresponding leasehold acquisition costs have been transferred to the amortization base.The Company estimates that evaluation of most of these properties and the inclusion of their costs in theamortization base is expected to be completed within five years.

The 2009 and 2008 property acquisition costs were related primarily to the Company’s leasingactivities in the Haynesville shale play. These costs are associated with acreage for which proved reserveshave yet to be assigned. The Company estimates that evaluation of most of these properties and theinclusion of their costs in the amortization base is expected to be completed within three to five years.Property acquisition costs incurred in 2007 and prior years were related primarily to the Company’s leasingactivities in southwest Wyoming, northeast Utah and southeast Idaho. The majority of the leases acquired inthese areas have primary expiration terms of five to ten years and do not begin to expire until various timesin 2012. At December 31, 2010, the Company was preparing to drill its first exploration well on this acreagein southwest Wyoming. The Company estimates that evaluation of most of these properties and theinclusion of their costs in the amortization base is expected to be completed within two to five years.

Costs excluded from amortization also include those costs associated with exploration anddevelopment wells in progress or awaiting completion at year-end. These costs are transferred into theamortization base on an ongoing basis, as these wells are completed and proved reserves are established orconfirmed. These costs totaled $35,906,656 at December 31, 2010 and were all associated with explorationwells. The Company anticipates that the entire $35,906,656 associated with these wells in progress atDecember 31, 2010 will be transferred to the amortization base during 2011. At December 31, 2010, therewere no well costs excluded from amortization that were incurred in years prior to 2010.

F-21



December 31, 2010, 2009 and 2008

NOTE 4 — ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in the Company’s asset retirement obligations for theyears ended December 31, 2010 and 2009.


2010 2009

Beginning asset retirement obligations . . . . . . . . . $2,551,637 $1,763,299Liabilities incurred during period . . . . . . . . . 847,845 199,556Revisions in estimated cash flows . . . . . . . . . 140,779 634,745Liabilities settled during period . . . . . . . . . . . – (183,310)Accretion expense . . . . . . . . . . . . . . . . . . . . . 154,756 137,347

Ending asset retirement obligations . . . . . . . . . . . . $3,695,017 $2,551,637

NOTE 5 — ASSET SALES AND IMPAIRMENT

In December 2010, the Company wrote off the Boise South Pipeline asset in Orange County, Texasfrom its Longwood Gathering and Disposal Systems, LP subsidiary and recorded a net loss of $173,690.The decision to write off this asset resulted from the fact that natural gas is no longer being put through thispipeline, nor is natural gas expected to be put through this pipeline in the future. In December 2010, theCompany also recorded an impairment to some of its equipment held in inventory following a determinationthat the current market value of the equipment, consisting primarily of drilling rig parts, was less than thecost. The carrying value of the inventory was reduced by $50,000 on the balance sheet, and a correspondingcharge was recorded to the consolidated statement of operations.

In December 2009, the Company recorded an impairment to some of its equipment held in inventoryfollowing a determination that the current market value of the equipment, consisting primarily of drilling rigparts, was less than the cost. The carrying value of the inventory was reduced by $323,500 on the balancesheet, and a corresponding charge was recorded to the consolidated statement of operations. In addition, theCompany recorded a loss of $55,816 on certain other equipment that was sold during 2009.

In July 2008, the Company signed an agreement with Chesapeake for the joint exploration anddevelopment of the Haynesville shale formation (underlying its existing Cotton Valley production) on theCompany’s Elm Grove/Caspiana leasehold in north Louisiana and received proceeds of $182,281,196. Atthe time of the Chesapeake transaction, the Company had no production from and no reserves assigned tothe Haynesville formation. As noted previously, sales of the Company’s oil and natural gas properties aretypically accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless suchadjustments would significantly alter the relationship between net capitalized costs and proved reserves ofoil and natural gas (see Note 2). In accounting for this transaction, the Company concluded that suchtreatment would, in fact, substantially alter the relationship between net capitalized costs and provedreserves of oil and natural gas. Further, the Company determined there were significant differences betweenthe properties sold and those retained, and in accordance with SEC Rule 4-10(C)(6)(i), capitalized costsshould be allocated on the basis of the relative fair value of the properties at the time of the sale. TheCompany estimated that it sold approximately one-third of the then-fair value of its oil and natural gas

F-22



December 31, 2010, 2009 and 2008

NOTE 5 — ASSET SALES AND IMPAIRMENT — Continued

properties in this transaction, and corresponding adjustments were made to its net capitalized costs. TheCompany reported a gain on this sale of $137,021,015, which is reflected in its consolidated statement ofoperations for 2008.

Additionally, in November 2008, certain equipment held in inventory was sold. The Companyrecorded a loss of $43,585 on the sale of this inventory.

NOTE 6 — REVOLVING CREDIT AGREEMENT

In March 2008, the Company entered into the Credit Agreement with Comerica Bank asAdministrative Agent, Syndication and Documentation Agent and Issuing Lender. The Credit Agreement issecured by a significant portion of the Company’s oil and natural gas producing properties and by the equityinterests of all its subsidiaries. In addition, all obligations under the Credit Agreement are guaranteed by theCompany’s subsidiaries. The Credit Agreement matures in March 2013.

Borrowings under the Credit Agreement are limited to the lesser of $150,000,000 or the borrowingbase, which is determined by the bank semi-annually on May 1 and November 1. The Company andComerica Bank may each request an unscheduled redetermination of the borrowing base one time duringany 12-month period. The borrowing base is adjusted at the discretion of the bank and is based in part onestimates of the Company’s proved oil and natural gas reserves, but also on external factors, such asComerica Bank’s lending policies and estimates of future oil and natural gas prices, over which theCompany has no control. In the event of a borrowing base increase, the Company pays a fee to ComericaBank equal to 0.25% of the amount of the increase. If the borrowing base were to be less than theoutstanding borrowings under the Credit Agreement at any time, the Company would be required to provideadditional collateral satisfactory in nature and value to Comerica Bank to increase the borrowing base to anamount sufficient to cover such excess or to repay the deficit in equal installments over a period of sixmonths.

Borrowings under the Credit Agreement are subject to varying interest rates based on the totaloutstanding borrowings relative to the borrowing base and whether the loan is a Eurodollar loan or a baserate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin of 1.250% to1.875% based on the ratio of outstanding borrowings to the borrowing base. The Eurodollar rate for anyinterest period (one, two, three, six or twelve months as designated by the Company) is the rate equal toLIBOR, as published by Bloomberg Financial Markets Information Service or another source agreed uponby the Company and Comerica Bank, for deposits in United States dollars for a similar interest period. Thebase rate is the higher of the federal funds rate plus 1.0% or the annual rate of interest designated byComerica Bank as its prime rate. A commitment fee of 0.250% to 0.375% based on the unused portion ofthe borrowing base is paid quarterly in arrears.

Key financial covenants under the Credit Agreement require the Company to maintain (1) a minimumcurrent ratio (defined as total current assets plus availability under the Credit Agreement divided by totalcurrent liabilities) of 1.0 or greater at all times and (2) a debt to EBITDA ratio (defined as total debtoutstanding divided by a rolling four-quarter EBITDA) of 3.75 or less at all times beginning twelve months

F-23



December 31, 2010, 2009 and 2008

NOTE 6 — REVOLVING CREDIT AGREEMENT — Continued

from closing (4.00 or less until that time). Other restrictive covenants (1) prevent the Company fromincurring other debt, subject to permitted exceptions, (2) prohibit the Company from declaring and payingdividends, except on its Class B common stock, and (3) limit the aggregate amount of oil and natural gasproduction that can be hedged pursuant to commodity hedging agreements and the maturity of thoseagreements. The Company was in compliance with all Comerica Bank’s covenants at December 31, 2010,2009 and 2008.

At December 31, 2009 and 2008, the borrowing base was $20,000,000. In December 2010, the CreditAgreement was amended to increase the borrowing base from $20,000,000 to $55,000,000. AtDecember 31, 2010, the Company had $25,000,000 of outstanding borrowings under the Credit Agreementand $50,000 in letters of credit secured by the Credit Agreement. At December 31, 2010, all borrowingsunder the Credit Agreement were Eurodollar loans, and the interest rate on the outstanding borrowings was1.553%. The Company had an additional $325,000 in letters of credit secured by CD’s at Comerica Bank atDecember 31, 2010. The Company had no borrowings under the Credit Agreement at December 31, 2009and 2008.

The Company obtained a written extension from Comerica Bank until July 15, 2011 to comply with acovenant under the Credit Agreement requiring submission of audited annual financial statements within120 days of the prior year end and the submission of unaudited quarterly financial statements within 45 daysof the prior quarter end. The Company submitted both sets of financial statements to Comerica Bank priorto this deadline.

NOTE 7 — INCOME TAXES

Deferred tax assets and liabilities are the result of temporary differences between the financialstatement carrying values and the tax bases of assets and liabilities. The Company’s net deferred taxposition at December 31, 2010 and 2009, respectively, is as follows.

December 31,

2010 2009

Deferred tax assetsNet operating loss — federal and

state . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 21,768,007 $ 12,003,245Federal alternative minimum tax . . . . . . 6,659,528 8,070,166

Total deferred tax assets . . . . . . . . . 28,427,535 20,073,411Deferred tax liabilities

Property and equipment . . . . . . . . . . . . . (33,800,718) (21,834,370)Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,533,074) (213,515)

Total deferred tax liabilities . . . . . . (35,333,792) (22,047,885)

Total net deferred taxliabilities . . . . . . . . . . . . . . . $ (6,906,257) $ (1,974,474)

F-24



December 31, 2010, 2009 and 2008

NOTE 7 — INCOME TAXES — Continued

At December 31, 2010, the Company recorded $1,473,619 of its deferred tax liabilities as current;these liabilities were attributable to the current portion of its unrealized derivative fair value.

At December 31, 2010, the Company had net operating loss carryforwards of $59,003,700 for federalincome tax purposes and $49,317,749 for state income tax purposes available to offset future taxableincome, as limited by the applicable provisions, and which expire at various dates through the tax yearending December 31, 2030.

The income tax expense reconciled to the tax computed at the statutory federal rate for the years endedDecember 31, 2010, 2009 and 2008, respectively, is as follows.


2010 2009 2008

Current income tax provision (benefit)State income tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 30 $ (994,504) $ 1,048,000Federal alternative minimum tax . . . . . . . . . . . . . . . . (1,410,638) (1,329,834) 9,400,000

Net current income tax provision (benefit) . . . . (1,410,608) (2,324,338) 10,448,000Deferred income tax provision

Federal tax expense at statutory rate (34%) . . . . . . . . 3,365,367 (7,941,036) 41,770,049Statutory depletion carryover . . . . . . . . . . . . . . . . . . (157,278) (610,013) (273,484)Change in state rate applied . . . . . . . . . . . . . . . . . . . . 275,030 (158,638) 2,183,239Nondeductible (additional) expense . . . . . . . . . . . . . 38,026 41,857 (1,542)Dividends received deduction . . . . . . . . . . . . . . . . . . – (262,815) –Federal alternative minimum tax . . . . . . . . . . . . . . . . 1,410,638 1,329,834 (9,400,000)Change in valuation allowance . . . . . . . . . . . . . . . . . – – (24,702,976)

Net deferred income tax provision . . . . . . . . . . 4,931,783 (7,600,811) 9,575,286

Total income tax provision (benefit) . . . . . $ 3,521,175 $(9,925,149) $ 20,023,286

As a result of the sale of certain assets in 2008 (see Note 5) resulting in the use of a majority of theCompany’s net operating loss carryforwards, the Company released the valuation allowance against itsremaining deferred tax assets in the amount of $24,702,976. The Company believes it is more likely thannot that future income, including income that may be generated as a result of certain tax planning strategies,together with future reversals of existing temporary tax differences, will be sufficient to fully recover theremaining deferred tax assets. Should the Company determine that all or part of its net deferred tax assetsmay not be realizable in the future, the Company will make an adjustment to the valuation allowance thatwould be charged against operations in the period such determination is made.

The Company files a United States federal income tax return and several state tax returns, a number ofwhich remain open for examination. The tax years open for examination for the federal tax return are 2007,2008, 2009 and 2010. The tax years open for examination by the state of Texas are 2008, 2009 and 2010.The tax years open for examination by the state of Louisiana are 2007, 2008, 2009 and 2010. At August 12,

F-25



December 31, 2010, 2009 and 2008

NOTE 7 — INCOME TAXES — Continued

2011, the Company’s 2007, 2008 and 2009 income and franchise tax returns are under examination by thestate of Louisiana. The tax years open for examination by the state of New Mexico are 2008, 2009 and2010. The Company has not paid any interest or penalties associated with its income taxes.

NOTE 8 — EMPLOYEE BENEFIT PLANS

Stock Options, Restricted Stock Grants and Performance Awards

The Company’s Board of Directors and shareholders approved in 2003 the Matador ResourcesCompany 2003 Stock and Incentive Plan (“Stock and Incentive Plan”). The Stock and Incentive Plan, asamended, provides that a maximum of 3,481,569 shares of Class A common stock in the aggregate may beissued pursuant to options or restricted stock grants. The persons eligible to receive awards under the Stockand Incentive Plan include employees, directors, officers, consultants or advisors of the Company.

The Stock and Incentive Plan is administered by the Board of Directors, which determines the numberof option or restricted shares to be granted, the effective dates and terms of the grants, the option orrestricted share price, and the vesting period. Incentive stock options become exercisable in one to fouryears from the grant date and expire five years or ten years after the grant date. Non-qualified optionsbecome exercisable immediately upon grant and expire five years after the grant date. In the absence of anestablished market for shares of the Company’s common stock, the Board of Directors determines the fairmarket value of the Company’s common stock for purposes of awards under the Stock and Incentive Plan.The Company typically uses newly issued shares of common stock to satisfy option exercises or restrictedshare grants.

Non-qualified stock option expense is recognized in the Company’s consolidated statement ofoperations on the date of grant. Incentive stock option expense is recognized on a straight-line basis over thevesting period. Prior to November 22, 2010, all of the Company’s outstanding stock options were classifiedas equity instruments, with all stock-based compensation expense measured on the date of grant andrecognized over the vesting period, if any.

Prior to November 22, 2010, the fair value of stock options granted under the Stock and Incentive Planwas estimated using the following weighted average assumptions for 2010, 2009 and 2008, respectively.


2010 2009 2008

Stock option pricing model . . . . . . . . . . . . . . . . . . Binomial Lattice Binomial Lattice Binomial LatticeExpected option life . . . . . . . . . . . . . . . . . . . . . . . . 5.41 years 3.73 years 4.14 yearsRisk-free interest rate . . . . . . . . . . . . . . . . . . . . . . . 2.58% 2.43% 2.84%Volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46.17% 52.55% 35.35%Dividend yield . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.0% 0.0% 0.0%Estimated forfeiture rate . . . . . . . . . . . . . . . . . . . . . 11.15% 3.39% 11.39%Weighted average fair value of options granted

during the year . . . . . . . . . . . . . . . . . . . . . . . . . . $3.02 $1.82 $1.76

F-26



December 31, 2010, 2009 and 2008

NOTE 8 — EMPLOYEE BENEFIT PLANS — Continued

On November 22, 2010, the Company changed its method of accounting for its outstanding stockoptions, reclassifying all outstanding stock options from equity to liability instruments (see Note 2). As aresult, at December 31, 2010, the Company measured and recognized the fair value of the liabilityassociated with its outstanding stock options using an estimated fair value of $11.00 per share for theCompany’s Class A common stock.

Summarized information about stock options outstanding under the Company’s Stock and IncentivePlan is as follows.

Number ofoptions

Priceper share

Aggregateoption price

Weightedaverage

exercise price

Options outstanding at January 1, 2008 . . . . . . . . . 1,669,875 $10,139,250 $ 6.07Options granted . . . . . . . . . . . . . . . . . . . . . . . 608,250 $10.00-13.33 6,362,500 10.46Options exercised . . . . . . . . . . . . . . . . . . . . . . (235,500) 3.33-13.33 (1,048,500) 4.45Options forfeited . . . . . . . . . . . . . . . . . . . . . . (154,875) 3.33-10.00 (1,020,750) 6.59

Options outstanding at December 31, 2008 . . . . . . 1,887,750 $14,432,500 $ 7.65Options granted . . . . . . . . . . . . . . . . . . . . . . . 45,000 $ 7.50 337,500 7.50Options exercised . . . . . . . . . . . . . . . . . . . . . . (343,500) 3.33-5.00 (1,281,500) 3.73Options forfeited . . . . . . . . . . . . . . . . . . . . . . (37,500) 3.33-13.33 (360,500) 9.61

Options outstanding at December 31, 2009 . . . . . . 1,551,750 13,128,000 8.46Options granted . . . . . . . . . . . . . . . . . . . . . . . 158,000 $ 9.00-11.00 1,468,000 9.29Options exercised . . . . . . . . . . . . . . . . . . . . . . (392,375) 5.00-10.00 (1,978,375) 5.04Options forfeited or expired . . . . . . . . . . . . . . (99,875) 5.00-13.33 (773,875) 7.75

Options outstanding at December 31, 2010 . . . . . . 1,217,500 $11,843,750 $ 9.73

Options outstanding Options exercisable

Range of exercise pricesShares

outstanding

Weightedaverage

remainingcontractual

life

Weightedaverageexercise

priceShares

exercisable

Weightedaverageexercise

price

$7.50-$9.00 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 566,750 2.99 years $ 8.96 347,250 $ 8.98$10.00-$13.33 . . . . . . . . . . . . . . . . . . . . . . . . . . 650,750 2.41 years $10.40 352,500 $10.38

At December 31, 2010, the Company recognized a total stock-based liability of $1,250,467 resultingfrom the reclassification of its outstanding stock options from equity to liability instruments, including acharge to shareholders’ equity of $1,086,271 and an additional (non-cash) compensation expense of$164,196. The Company recorded $1,095,014 of this stock-based liability as a current liability and$155,453 as a long-term liability.

F-27



December 31, 2010, 2009 and 2008


At December 31, 2010, 2009 and 2008, the total remaining unrecognized compensation expenserelated to unvested stock options was approximately $376,986, $807,324 and $1,162,275, respectively, andthe weighted average remaining requisite service period (vesting period) of all unvested stock options wasapproximately 1.65, 1.93 and 2.53 years, respectively.

Non-vested stock options Shares

Weightedaverage

grant datefair value

Non-vested at January 1, 2010 . . . . . . . . . . . . . . . . . . . 658,125 $9.78Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158,000 9.29Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (246,750) 9.78Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (51,625) 8.33

Non-vested at December 31, 2010 . . . . . . . . . . . . . . . . 517,750 $9.78

The fair value of option shares vested during 2010 was $2,413,250. Total compensation (non-cash)costs for stock-based payment arrangements recognized in the Company’s consolidated statement ofoperations were $897,737 for the year ending December 31, 2010. The tax-related benefit from the exerciseof stock options totaled $779,907 for 2010.

On May 17, 2007, the Company made a restricted stock grant of 4,500 shares of Class A commonstock to an employee. These shares vested according to the following schedule: 1,500 shares each onDecember 31, 2007, 2008 and 2009, respectively. At December 31, 2009, all 4,500 shares were vested tothe employee.

On February 13, 2008, the Company made a restricted stock grant of 9,000 shares of Class A commonstock to an employee. These shares vested according to the following schedule: 3,000 shares each onDecember 31, 2008, 2009 and 2010, respectively. At December 31, 2010, all 9,000 shares were vested tothe employee.

On October 28, 2010, the Company made a restricted stock grant of 15,000 shares of Class A commonstock to an employee. These shares vested or will vest according to the following schedule: 3,000 shareswere fully vested upon grant and an incremental 4,000 shares will vest on each of October 28, 2011, 2012and 2013. Should the employee cease to remain in service with the Company other than by death ordisability, all unvested shares will be forfeited.

Following the closing of its transaction with Chesapeake in July 2008, the Board of Directors and/orCompany management authorized the award of one-time, special cash bonuses to eligible employees inrecognition of the significant increase in the Company’s value achieved as a result of the transaction and asan incentive to retain these employees. The Company recorded a compensation expense of $1,660,375related to these bonuses in 2008.

In October 2008, the Company’s Board of Directors approved the adoption of the Employee ShareRepurchase Program (“Repurchase Program”) authorizing the Company to repurchase shares of its Class A

F-28



December 31, 2010, 2009 and 2008


common stock from its employees, directors and officers, subject to certain conditions and restrictions. In2010, the Company repurchased 117,505 shares of Class A common stock at $11.00 per share from thirteenemployees (including the Executive Vice President, Chief Financial Officer and Chief Operating Officer,the Executive Vice President — Operations and the Vice President — Reservoir Engineering). In 2009, theCompany repurchased 114,000 shares of Class A common stock at $7.33-$7.50 per share from tenemployees (including the Vice President — Reservoir Engineering and the Vice President — Geophysicsand New Ventures). In 2008, the Company repurchased 26,250 shares of Class A common stock at $13.33per share from three employees (including the Vice President — Geophysics and New Ventures). Nodirector nor the Company’s Chairman and Chief Executive Officer has ever participated in the RepurchaseProgram. The Company’s Board of Directors terminated the Repurchase Program in April 2011, and theCompany is no longer authorized to repurchase shares of Class A common stock from its employees,directors and officers. No shares were repurchased in 2011 prior to the termination of the RepurchaseProgram by the Board of Directors.

In October 2008, the Company’s Board of Directors approved the adoption of the Employee OptionExercise Loan Program (“Loan Program”), authorizing the Company to establish a loan program with afinancial institution to assist its employees, directors and officers in the exercise of their outstanding optionsto purchase shares of Class A common stock, subject to certain conditions and restrictions outlined in theLoan Program. As part of the Loan Program, the Company provides the financial institution with a guarantyof repayment of the loan and makes deposits of funds in certificates of deposit to secure its guaranty.Notwithstanding the guaranty, these loans are full recourse obligations of each loan recipient, and each loanrecipient agrees to indemnify and reimburse the Company in full for all liabilities incurred by the Companyin the event of the recipient’s default on the loan. Each loan recipient also pledges all shares purchased fromthe Company with the loan proceeds to further secure his or her obligations to the Company in return for itsguaranty. No director nor the Company’s Chairman and Chief Executive Officer has ever participated in theLoan Program.

At December 31, 2010, the Company had secured the loans of eight employees (including theExecutive Vice President, Chief Financial Officer and Chief Operating Officer, the Executive VicePresident — Operations and the Vice President — Reservoir Engineering) pursuant to this Loan Program inthe aggregate amount of $1,326,000. The Company considers the fair value of this aggregate guaranty to beminimal and has recorded no liability provision associated with this guaranty on its consolidated balancesheets in any reporting period presented. The Company’s Board of Directors terminated the Loan Programin April 2011, and the Company is no longer authorized to provide financial guaranties for additional loans.No new loans were guaranteed in 2011 prior to the termination of the Loan Program by the Board ofDirectors.

401(k) Plan

Effective July 3, 2003, the Company established a defined contribution retirement plan. All full-timeCompany employees are eligible to join the plan the first day of the calendar month immediately followingtheir date of employment. Each participant may contribute up to the maximum allowable under the Internal

F-29



December 31, 2010, 2009 and 2008


Revenue Code. Each year, the Company makes a contribution to the plan which equals 3% of theemployee’s annual compensation, referred to as the Employer’s Safe Harbor Non-Elective Contribution.The Company’s Safe Harbor match was $159,995, $140,543 and $142,779 in 2010, 2009 and 2008,respectively. In addition, each year the Company may determine and make a discretionary matchingcontribution as well as additional contributions. The Company’s discretionary matching contributionstotaled $197,504, $167,456 and $176,545 in 2010, 2009 and 2008, respectively. The Company made noadditional discretionary contributions in any reporting period presented.

NOTE 9 — COMMON STOCK

Increase in Authorized Shares

On October 23, 2008, at a Special Meeting of Shareholders called for the express purpose, theCompany’s shareholders approved an amendment to the Articles of Incorporation of the Companyincreasing the number of shares of Class A common stock authorized to be issued by the Company to80,000,000 shares having a par value of $0.01 per share.

Stock Split

The Company declared a three-for-one split of all its issued and outstanding shares of Class A andClass B common stock effective October 31, 2008. Each Class A and Class B shareholder received two newshares of Class A common stock for each share of Class A and Class B common stock held of record atOctober 31, 2008. All common shares and per common share amounts in the accompanying consolidatedfinancial statements and notes have been adjusted to affect this stock split retroactively.

Dividends

The Company has issued two classes of common stock, Class A and Class B. The holders of the ClassB shares are entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of fundslegally available for the payment of dividends. These dividends are accrued and paid quarterly. Dividendsdeclared during 2010, 2009 and 2008 totaled $274,853 in each year. Dividends for the fourth quarter of2010 were accrued and paid in January 2011. Dividends for the fourth quarter of 2009 and 2008 wereaccrued and paid in January 2010 and 2009, respectively. At December 31, 2010, the Company has not paidany dividends to holders of the Class A shares.

Stock Offerings, Retirement and Issuances

In October 2010, the Board of Directors approved and authorized the private offering and sale ofadditional shares of the Company’s Class A common stock at $11.00 per share in the period from October2010 through January 2011. At December 31, 2010, the Company sold 1,868,427 shares and received netproceeds of $20,536,167. In January 2011, the Company sold an additional 53,772 shares as part of thisprivate offering and received net proceeds of $584,918. The Company also sold 11,000 shares of Class Acommon stock at $9.00 per share to an accredited investor and received net proceeds of $99,000 in May2010.

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December 31, 2010, 2009 and 2008

NOTE 9 — COMMON STOCK — Continued

In February 2009, one of the Company’s largest shareholders at the time, Gandhara Capital(“Gandhara”), a large international hedge fund, notified the Company of its need to sell its entire holdingsof the Company’s Class A common stock totaling 5,422,713 shares due to its plan for liquidation. TheBoard of Directors unanimously authorized the repurchase of all of Gandhara’s outstanding shares at $5.00per share, and Gandhara accepted this offer. In April 2009, the Company repurchased 5,422,713 shares ofits Class A common stock from Gandhara for $27,113,565. These shares were effectively retired by theCompany; however, this share repurchase and effective retirement did not reduce the 80,000,000 totalshares authorized for issue by the Company.

Following the repurchase of these shares from Gandhara, the Board of Directors approved andauthorized the Company’s May 2009 private offering in which the Company sold 4,950,694 shares ofClass A common stock and received net proceeds of $27,982,569. In addition to this private offering, theCompany sold 23,500 shares of Class A common stock to two accredited shareholders and received netproceeds of $176,250 during 2009.

Treasury Stock

During 2010, the Company issued 6,000 shares of Class A common stock valued at $7.50-$9.00 pershare from treasury stock. The Company also purchased 1,117,505 shares of Class A common stock for$9.00-$11.00 per share. These purchases included 1,000,000 shares of Class A common stock purchasedfrom five shareholders, all advised by Wellington Management Company, in April 2010 at $9.00 per share,for a total of $9,000,000.

During 2009, the Company issued 652,126 shares of Class A common stock valued at $5.00-$7.50 pershare from treasury stock. The Company also purchased 679,923 shares of Class A common stock fromcertain shareholders at $5.00-$7.50 per share.

During 2008, the Company issued 5,775 shares of Class A common stock valued at $13.33 per sharefrom treasury stock. The Company also purchased 450 and 26,250 shares of Class A common stock fromcertain shareholders at $10.00 and $13.33 per share, respectively.

NOTE 10 — DERIVATIVE FINANCIAL INSTRUMENTS

From time to time, the Company uses derivative financial instruments to hedge its exposure tocommodity price risk associated with natural gas prices. These instruments consist of put and call options inthe form of costless collars. The Company records derivative financial instruments on its balance sheet aseither an asset or a liability measured at fair value. The Company has elected not to apply hedge accountingfor its existing derivative financial instruments. As a result, the Company recognizes the change inderivative fair value between reporting periods currently in its consolidated statement of operations as anunrealized gain or loss. The fair value of the Company’s derivative financial instruments is determinedbased on its counterparty’s valuation model, which the Company verifies for its reasonableness with anindependent third-party valuation using observable, market-corroborated inputs.

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December 31, 2010, 2009 and 2008

NOTE 10 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

During 2010, 2009 and 2008, the Company entered into various costless collar transactions, each withan established price floor and ceiling. For each calculation period, the specified price for determining therealized gain or loss to the Company pursuant to any of these transactions is the settlement price for theNYMEX Henry Hub natural gas futures contract for the delivery month corresponding to the calculationperiod’s calendar month for the last day of that contract period. When the settlement price is below the pricefloor established by these collars, the Company receives from Comerica Bank, as counterparty, an amountequal to the difference between the settlement price and the price floor multiplied by the contract natural gasvolume hedged. When the settlement price is above the price ceiling established by these collars, theCompany pays to Comerica Bank, as counterparty, an amount equal to the difference between thesettlement price and the price ceiling multiplied by the contract natural gas volume hedged.

At December 31, 2010, the Company had seven costless collar contracts open and in place to mitigateits exposure to natural gas price volatility, each with a specific term (calculation period), notional quantity(volume hedged) and price floor and ceiling. Each contract is set to expire at varying times during 2011.The Company has no hedging contracts in place with regard to any of its oil production, and no hedgingcontracts in place beyond 2011 with regard to any of its natural gas production.

The following is a summary of the Company’s open costless collar contracts at December 31, 2010.

Commodity Calculation PeriodNotionalQuantity

PriceFloor

PriceCeiling

Fair Valueof Asset

(MMBtu/month) ($/MMBtu) ($/MMBtu)

Natural Gas . . . . . . . . . 01/01/2010 - 12/31/2011 50,000 5.25 8.10 $ 533,839Natural Gas . . . . . . . . . 01/01/2010 - 12/31/2011 50,000 5.50 7.65 649,497Natural Gas . . . . . . . . . 01/01/2010 - 12/31/2011 50,000 5.00 8.65 420,065Natural Gas . . . . . . . . . 01/01/2010 - 12/31/2011 50,000 5.50 7.70 649,497Natural Gas . . . . . . . . . 01/01/2011 - 12/31/2011 90,000 5.50 7.85 1,172,754Natural Gas . . . . . . . . . 11/01/2010 - 03/31/2011 120,000 6.00 7.65 597,038Natural Gas . . . . . . . . . 07/01/2010 - 06/30/2011 60,000 4.50 6.55 121,721

Total . . . . . . . . . . . $4,144,411

Additional Disclosures about Derivative Financial Instruments

The following table summarizes the location and fair value of all derivative financial instrumentsrecorded in the consolidated balance sheets for the periods presented. These derivative financial instrumentsare not designated as hedging instruments.

Type of Instrument Location in Balance Sheet

December 31,

2010 2009

Derivative InstrumentNatural Gas . . . Current assets: Derivative instruments $4,144,411 $1,005,685

Total . . . . . $4,144,411 $1,005,685

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December 31, 2010, 2009 and 2008


The following table summarizes the location and fair value of all derivative financial instrumentsrecorded in the consolidated statements of operations for the periods presented. These derivative financialinstruments are not designated as hedging instruments.

Type of InstrumentLocation in

Statement of Operations


2010 2009 2008

Derivative InstrumentNatural Gas . . . . . Revenues: Realized gain (loss) on

derivatives $5,299,380 $ 7,625,120 $(1,325,970)Revenues: Unrealized gain (loss) onderivatives 3,138,726 (2,374,638) 3,591,928

Total . . . . . . $8,438,106 $ 5,250,482 $ 2,265,958

NOTE 11 — FAIR VALUE MEASUREMENTS

The Company measures and reports certain financial and non-financial assets and liabilities on a fairvalue basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in anorderly transaction between market participants at the measurement date (exit price). Fair valuemeasurements are classified and disclosed in one of the following categories.

Level 1 Unadjusted quoted prices in active markets that are accessible at the measurement date foridentical, unrestricted assets or liabilities. Active markets are considered to be those in whichtransactions for the assets or liabilities occur in sufficient frequency and volume to providepricing information on an ongoing basis.

Level 2 Quoted prices in markets that are not active, or inputs which are observable, either directly orindirectly, for substantially the full term of the asset or liability. This category includes thosederivative instruments that are valued using observable market data. Substantially all of theseinputs are observable in the marketplace throughout the full term of the derivative instrument,can be derived from observable data or supported by observable levels at which transactionsare executed in the marketplace.

Level 3 Unobservable inputs that are not corroborated by market data. This category is comprised offinancial and non-financial assets and liabilities whose fair value is estimated based oninternally developed models or methodologies using significant inputs that are generally lessreadily observable from objective sources.

Financial and non-financial assets and liabilities are classified based on the lowest level of input that issignificant to the fair value measurement. The assessment of the significance of a particular input to the fairvalue measurement requires judgment, which may affect the valuation of the fair value of assets andliabilities and their placement within the fair value hierarchy levels.

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December 31, 2010, 2009 and 2008

NOTE 11 — FAIR VALUE MEASUREMENTS — Continued

The following tables summarize the valuation of the Company’s financial assets and liabilities thatwere accounted for at fair value on a recurring basis in accordance with the classifications provided above atDecember 31, 2010 and 2009.

DescriptionFair Value Measurements at

December 31, 2010 using

Level 1 Level 2 Level 3 Total

Assets (Liabilities)Certificates of deposit . . . . . . . . . . . . . . . $– $ 2,349,313 $– $ 2,349,313Natural gas derivatives . . . . . . . . . . . . . . – 4,144,411 – 4,144,411

Total . . . . . . . . . . . . . . . . . . . . . . . . . $– $ 6,493,724 $– $ 6,493,724




Assets (Liabilities)Certificates of deposit . . . . . . . . . . . . . . . $– $15,675,346 $– $15,675,346Natural gas derivatives . . . . . . . . . . . . . . – 1,005,685 – 1,005,685

Total . . . . . . . . . . . . . . . . . . . . . . . . . $– $16,681,031 $– $16,681,031

The Company’s accounting policies for certificates of deposit and derivative financial instruments arediscussed in Note 2; additional disclosures related to derivative financial instruments are provided in Note10. For purposes of fair value measurement, the Company determined that CDs and derivative financialinstruments (e.g., natural gas derivatives) should be classified at Level 2.

Effective January 1, 2009, the Company adopted the new disclosure requirements for non-financialassets and liabilities that are measured at fair value on a non-recurring basis. The Company accounts foradditions to asset retirement obligations and lease and well equipment inventory at fair value on anon-recurring basis. The following tables summarize the valuation of the Company’s assets and liabilitiesthat were accounted for at fair value on a non-recurring basis at December 31, 2010 and 2009.




Assets (Liabilities)Asset retirement obligations . . . . . . . . . . . . . . $– $– $(847,845) $(847,845)Lease and well equipment inventory . . . . . . . – – 442,500 442,500

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . $– $– $(405,345) $(405,345)

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December 31, 2010, 2009 and 2008






Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . $– $– $(292,944) $(292,944)

The Company’s accounting policies for asset retirement obligations are discussed in Note 2;reconciliations of the Company’s asset retirement obligations are provided in Note 4 for the periodspresented. For purposes of fair value measurement, the Company determined that the additions to assetretirement obligations should be classified at Level 3. The Company recorded additions to asset retirementobligations of $847,845 and $199,556 in 2010 and 2009, respectively.

The Company’s accounting policies for lease and well equipment inventory are discussed in Note 2.For purposes of fair value measurement, the Company determined that lease and well equipment inventoryshould be classified at Level 3. The Company recorded an impairment to some of its equipment held ininventory, consisting primarily of drilling rig parts, of $50,000 and $323,500 in 2010 and 2009,respectively. The Company periodically obtains estimates of the market value of its drilling rig parts held ininventory from an independent third-party seller of similar equipment and uses these estimates as a basis forits measurement of the fair value of its drilling rig parts.

NOTE 12 — COMMITMENTS AND CONTINGENCIES

Office Lease

The Company’s corporate headquarters are located in 20,869 square feet of office space at One LincolnCentre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas. The office lease commencement date wasSeptember 25, 2003 with an expiration date of June 30, 2011. In December 2010, the Company agreed to athird amendment to its office lease agreement, in which the office space will be increased to 26,089 squarefeet and the term of the lease is extended from July 1, 2011 to June 30, 2022. The effective base rent overthe term of the new lease extension is $19.75 per square foot per year.

The following is a schedule of future minimum lease payments required under the office leaseagreement at December 31, 2010.

Year ending December 31, Amount

2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 207,2322012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 260,8902013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 521,7802014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 521,7802015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 534,825Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,827,256

F-35



December 31, 2010, 2009 and 2008

NOTE 12 — COMMITMENTS AND CONTINGENCIES — Continued

Rent expense, including fees for operating expenses and consumption of electricity, was $386,092,$417,371 and $431,880 for 2010, 2009 and 2008, respectively.

Other Capital Commitments

At December 31, 2010, the Company had outstanding capital commitments to participate in the drillingand completion of 10 gross non-operated wells in the Haynesville shale in north Louisiana. The Companyhas a 1.9% working interest in each well. At December 31, 2010, the Company had minimum outstandingcapital commitments for its participation in these wells of approximately $1.7 million, assuming that all 10wells were subsequently drilled and completed by the operator. The Company expects these costs to beincurred in the next 12 months.

At December 31, 2010, the Company had outstanding capital commitments with a geophysicalcontractor for two 3D seismic acquisition projects on a portion of its Eagle Ford acreage in south Texas andwith a division of Core Laboratories, LP for core analysis services. At December 31, 2010, the outstandingaggregate capital commitments for these projects were approximately $1.2 million, and the Companyexpects these costs to be incurred in the next 12 months.

Legal Proceedings

The Company is a defendant in four lawsuits encountered in the ordinary course of its business, noneof which, in the opinion of management, will have a material adverse impact on the Company’s financialposition, results of operations or cash flows. Certain of these matters are covered to an extent by insurance.In other cases, the Company believes it has a meritorious defense.

General Federal and State Regulations

Oil and natural gas exploration, production and related operations are subject to extensive federal andstate laws, rules and regulations. Failure to comply with these laws, rules and regulations can result insubstantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doingbusiness and affects profitability. The Company believes that it is in compliance with currently applicablestate and federal regulations. Because these rules and regulations are frequently amended or reinterpreted,however, the Company is unable to predict the future cost or impact of complying with these regulations.

Environmental Regulations

The exploration, development and production of oil and natural gas, including the operation ofsaltwater injection and disposal wells, are subject to various federal, state and local environmental laws andregulations. These laws and regulations can increase the costs of planning, designing, installing, andoperating oil and natural gas wells. The Company’s activities are subject to a variety of environmental lawsand regulations, including, but not limited to, the Oil Pollution Act of 1990, the Clean Water Act, theComprehensive Environmental Response, Compensation and Liability Act, the Resource Conservation andRecovery Act, the Clean Air Act, the Safe Drinking Water Act, and the Occupational Safety and Health

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December 31, 2010, 2009 and 2008


Act, as well as comparable state statutes and regulations. The Company is also subject to regulationsgoverning the handling, transportation, storage and disposal of waste generated by its activities and ofnaturally occurring radioactive materials, or NORM, that may result from its oil and natural gas operations.Civil and criminal fines and penalties may be imposed for noncompliance with these environmental lawsand regulations. Additionally, these laws and regulations require the acquisition of permits or othergovernmental authorizations before undertaking some activities, limit or prohibit other activities because ofprotected wetlands, areas or species, and require investigation and cleanup of pollution. The Company hasno outstanding material environmental remediation liabilities and believes that it is in compliance withcurrently applicable environmental laws and regulations and that these laws and regulations will not have amaterial adverse impact on the financial position, results of operations or cash flows of the Company.

Changes in environmental laws and regulations occur frequently, however, and any changes that resultin more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could, andin all likelihood would, materially adversely affect the Company’s financial position, results of operationsand cash flows, as well as those of the oil and natural gas industry in general. Because these rules andregulations are frequently amended or reinterpreted, the Company is unable to predict the future cost orimpact of complying with these regulations. For instance, recent scientific studies have suggested thatemissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide andmethane, may be contributing to the warming of the Earth’s atmosphere. As a result, there have beenattempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted.Any future federal or state laws or implementing regulations that may be adopted to address greenhouse gasemissions could, and in all likelihood would, require the Company to incur increased operating costsadversely affecting its financial position, results of operations and cash flows.

The Company’s activities involve the use of hydraulic fracturing. Recently, there has been increasingregulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as undergroundinjection at the federal level. At the federal level and in some states, there have been efforts to placeadditional regulatory burdens on hydraulic fracturing activities. In addition, certain bills have beenintroduced in the Senate and the House of Representatives that, if adopted, could increase the possibility oflitigation and establish an additional level of regulation at the federal level that could lead to operationaldelays or increased operating costs and could, and in all likelihood, would, result in additional regulatoryburdens, making it more difficult to perform hydraulic fracturing operations and increasing the Company’scosts of compliance. At the state level, Wyoming and Texas, for example, have enacted requirements for thedisclosure of the composition of the fluids used in hydraulic fracturing. On June 17, 2011, Texas signed intolaw a mandate for public disclosure of the chemicals that operators use during hydraulic fracturing in Texas.The law goes into effect September 1, 2011. State regulators have until 2013 to complete implementingrules. In addition, at least three local governments in Texas have imposed temporary moratoria on drillingpermits within city limits so that local ordinances may be reviewed to assess their adequacy to addresshydraulic fracturing activities. Additional burdens on hydraulic fracturing, such as reporting requirements orpermitting requirements for hydraulic fracturing activities, could, and in all likelihood would, result inadditional expense and delay the Company’s operations adversely affecting its financial position, results ofoperations and cash flows.

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December 31, 2010, 2009 and 2008


Oil and natural gas exploration and production, operations and other activities have been conducted atsome of the Company’s properties by previous owners and operators. Materials from these operationsremain on some of the properties, and, in some instances, require remediation. In addition, the Companyoccasionally must agree to indemnify sellers of producing properties the Company acquires against some orall of the liability for environmental claims associated with these properties. While the Company does notbelieve that the costs it incurs for compliance with environmental regulations and remediating previously orcurrently owned or operated properties will be material, the Company cannot provide assurances that thesecosts will not result in material expenditures that adversely affect its financial position, results of operationsand cash flows.

The Company maintains insurance against some, but not all, potential risks and losses associated withthe oil and natural gas industry and operations. The Company does not carry business interruptioninsurance. For some risks, the Company may not obtain insurance if it believes the cost of availableinsurance is excessive relative to the risks presented. In addition, pollution and environmental risksgenerally are not fully insurable. If a significant accident or other event occurs and is not fully covered byinsurance, it could, and in all likelihood would, materially adversely affect the Company’s financialposition, results of operations and cash flows.

NOTE 13 — MAJOR CUSTOMERS

For the year ended December 31, 2010, the Company had three significant purchasers that eachaccounted for more than 10% of its total oil and natural gas revenues: Chesapeake Operating, Inc. (42%),Regency Gas Services LP (17%) and Petrohawk Energy Corporation (11%). For the year endedDecember 31, 2009, the Company had three significant purchasers that each accounted for more than 10%of its total oil and natural gas revenues: Chesapeake Operating, Inc. (32%), Regency Gas Services LP(25%) and J-W Operating Company (17%). For the year ended December 31, 2008, the Company had twosignificant purchasers that each accounted for more than 10% of its total oil and natural gas revenues:Regency Gas Services LP (45%) and J-W Operating Company (24%). Due to the nature of the markets foroil and natural gas, the Company does not believe that the loss of any one purchaser would have a materialadverse impact on the Company’s financial position, results of operations or cash flows.

For the years ended December 31, 2010 and 2009, the Company had one industry partner thataccounted for approximately 93% and 94%, respectively, of its accounts receivable: Goodrich PetroleumCorporation.

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December 31, 2010, 2009 and 2008

NOTE 14 — SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at December 31, 2010 and2009.

December 31,

2010 2009

Accrued evaluated and unproved and unevaluated property costs . . $12,119,475 $3,932,500Accrued support equipment and facilities costs . . . . . . . . . . . . . . . . . 40,145 4,875Accrued cost to issue equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 359,175 –Accrued stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . 1,095,014 –Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,044,737 1,269,069

Total accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $14,658,546 $5,206,444

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the years endedDecember 31, 2010, 2009 and 2008.


2010 2009 2008

Cash (refunded) paid for income taxes . . . . . . . . . . . . . . . . . . . . $ (2,155,517) $(1,235,672) $10,400,000Asset retirement obligations related to mineral properties . . . . . 862,238 642,836 435,089Asset retirement obligations related to support equipment and

facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126,386 8,155 158,756Increase/(decrease) in liabilities for oil and natural gas

properties capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . 15,530,871 (2,470,798) (5,155,186)Increase in liabilities for support equipment and facilities . . . . . 39,657 – –Issuance of treasury stock for Board and advisor services . . . . . 47,250 29,375 77,000Increase in liabilities for accrued cost to issue equity . . . . . . . . . 359,174 – –Stock-based compensation expense recognized as liability . . . . 164,188 – –Transfer of inventory to oil and natural gas properties . . . . . . . . 353,395 – –

NOTE 15 — TRANSACTIONS WITH RELATED PARTIES

In January 2007, the Company entered into a joint venture with Marlan Downey and Julie DowneyGarvin of Roxanna Oil Company (“Roxanna”) to assemble acreage for and to market a new gas shaleprospect in southwest Wyoming, northeast Utah and southeast Idaho. Mr. Downey is a special advisor to theCompany’s Board of Directors and a shareholder in the Company. Ms. Garvin is President of Roxanna,which is also a shareholder in Matador. Mr. Downey and Ms. Garvin developed the prospect conceptindependently and sought the Company’s expertise in assembling a large acreage position across theprospect. To date, the Company has assembled over 140,000 acres across the prospect at a total cost of

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December 31, 2010, 2009 and 2008

NOTE 15 — TRANSACTIONS WITH RELATED PARTIES — Continued

approximately $9,300,000. The Company actively marketed this prospect in conjunction with Mr. Downeyand Ms. Garvin. In May 2010, the Company, Roxanna and its subsidiary, Roxanna Rocky Mountains, LLC,entered into participation and joint operating agreements with an industry partner for the joint explorationand development of this opportunity. Under these agreements, Roxanna Rocky Mountains, LLC reserves a2.5% overriding royalty interest in the leases and has the opportunity to earn up to a 10% working interestin all wells drilled. The industry partner has a 50% working interest in the project, and the Company retainsa working interest equal to the difference between 50% and the working interest participation elected byRoxanna Rocky Mountains, LLC. The Company, as operator, began drilling the initial test well for thisprospect located in Lincoln County, Wyoming in February 2011.

On April 15, 2008, Joseph Wm. Foran, the Company’s Chairman of the Board and Chief ExecutiveOfficer, made a partial assignment to the Company of his rights, title and interest in and to oil and gas leasesin lands located in southeast New Mexico, being specifically an undivided 29.222591% working interest ina 40-acre tract (approximately 12 net acres). Prior to this assignment, Mr. Foran had received a proposalfrom Samson Resources Company (“Samson”) requesting an assignment of this same undeveloped workinginterest in the subject lands in return for a substantial cash consideration and with Mr. Foran retaining a12.5% overriding royalty interest proportionally reduced. Mr. Foran offered the Company the opportunity toacquire this interest on terms more favorable to the Company than he was offered by Samson. Followingreview of this opportunity, the Company’s technical staff and management (excluding Mr. Foran)recommended pursuing an assignment of these leasehold interests from Mr. Foran. With the full approval ofthe Company’s management and Board of Directors (excluding Mr. Foran), Mr. Foran assigned to theCompany a 29.222591% working interest in the subject lands for no cash consideration, while retaining aproportionately reduced 12.5% overriding royalty interest as to the Company’s assigned working interestand a 4% working interest for his own account. Subsequent to this transaction, one well was drilled andcompleted as an oil producer by Samson, and both the Company and Mr. Foran participated in the drillingand completion of this well in accordance with their respective working interests.

NOTE 16 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited)

Costs Incurred

The following table summarizes costs incurred and capitalized by the Company in the acquisition,exploration, and development of oil and natural gas properties for the years ended December 31, 2010, 2009and 2008.


2010 2009 2008

Property acquisition costsProved . . . . . . . . . . . . . . . . . . . . . . $ – $ – $ –Unproved and unevaluated . . . . . . 100,730,019 24,803,480 30,508,649

Exploration costs . . . . . . . . . . . . . . . . . . 60,718,511 21,386,885 43,888,609Development costs . . . . . . . . . . . . . . . . 14,348,040 6,225,511 25,001,284

Total costs incurred . . . . . . . . . . . . $175,796,570 $52,415,876 $99,398,542

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December 31, 2010, 2009 and 2008

NOTE 16 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited) — Continued

Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gasproperties, including both unproved and unevaluated leasehold and purchases of reserves in place. For theyears ended December 31, 2010, 2009 and 2008, respectively, almost all of the Company’s propertyacquisition costs resulted from the acquisition of unproved and unevaluated leasehold positions.

Exploration costs are costs incurred in identifying areas of these oil and gas properties that maywarrant further examination and in examining specific areas that are considered to have prospects ofcontaining oil and natural gas, including costs of drilling exploratory wells, geological and geophysicalcosts, and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may beincurred before or after acquiring the related oil and natural gas properties.

Development costs are costs incurred to obtain access to proved reserves and to provide facilities forextracting, treating, gathering and storing oil and natural gas. Development costs include the costs ofpreparing well locations for drilling, drilling and equipping development wells and related service wells(e.g., salt water disposal wells), and acquiring, constructing and installing production facilities.

Costs incurred also include new asset retirement obligations established, as well as changes to assetretirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirementobligations included in the table above were $988,624, $650,991 and $593,845 for the years endedDecember 31, 2010, 2009 and 2008, respectively. Capitalized general and administrative expenses that aredirectly related to acquisition, exploration and development activities are also included in the table above.The Company capitalized $1,604,682, $1,642,868 and $1,679,992 of these internal costs in 2010, 2009 and2008, respectively.

Oil and Natural Gas Operating Results

The following table provides the results of operations from oil and gas producing activities, excludingcorporate overhead and interest costs, for the years ended December 31, 2010, 2009 and 2008.


2010 2009 2008

Oil and natural gas revenues . . . . . . . . . . . . . . . . . . . . . . $34,041,607 $ 19,038,514 $30,645,065Production taxes and marketing expenses . . . . . . . . . . . . 1,981,550 1,077,145 1,639,198Lease operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . 5,284,362 4,725,022 4,666,591Depletion, depreciation and amortization . . . . . . . . . . . . 15,423,044 10,510,769 11,786,399Full-cost ceiling impairment . . . . . . . . . . . . . . . . . . . . . . – 25,243,738 22,195,127

Net operating income (loss) . . . . . . . . . . . . . . . . . . . 11,352,651 (22,518,160) (9,642,250)Income tax provision (benefit) . . . . . . . . . . . . . . . . . . . . . 4,037,877 (8,006,782) (3,428,495)

Results of oil and natural gas operations . . . . . $ 7,314,774 $(14,511,378) $ (6,213,755)

Depletion, depreciation and amortization per MMcfe . . . $ 1.79 $ 2.10 $ 3.56

F-41



December 31, 2010, 2009 and 2008


Oil and Natural Gas Reserves

Proved reserves are estimated quantities of oil and natural gas which geological and engineering datademonstrate with reasonable certainty to be recoverable in future years from known reservoirs usingexisting economic and operating conditions. Estimating oil and natural gas reserves is complex and is notexact because of the numerous uncertainties inherent in the process. The process relies on interpretations ofavailable geological, geophysical, petrophysical, engineering and production data. The extent, quality andreliability of both the data and the associated interpretations of that data can vary. The process also requirescertain economic assumptions, including, but not limited to, oil and natural gas prices, drilling and operatingexpenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues,taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas mostlikely will vary from the Company’s estimates.

Oil and natural gas reserves are estimated using then-current operating and economic conditions, withno provision for price and cost escalations in future periods except by contractual arrangements. In January2009, the SEC issued The Modernization of Oil and Gas Reporting, Final Rule and in January 2010, theFASB amended Topic 932, Extractive Activities — Oil and Gas to align with this rule. As a result,beginning December 31, 2009, the commodity prices used to estimate oil and natural gas reserves are basedon unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous12-month period. For the period January through December 2010, these average oil and natural gas priceswere $75.96 per barrel and $4.376 per MMBtu (million British thermal units), respectively. For the periodJanuary through December 2009, these average oil and natural gas prices were $57.65 per barrel and $3.866per MMBtu, respectively. Prior to 2009, SEC guidelines for estimating and reporting oil and natural gasreserves required using commodity prices at the last day of the year. For 2008, these year-end oil andnatural gas prices were $41.00 per barrel and $5.71 per MMBtu, respectively.

The Company’s oil and natural gas reserves estimates are prepared by the Company’s engineering staffin accordance with guidelines established by the SEC and then audited for their reasonableness andconformance with SEC guidelines and generally accepted petroleum engineering and evaluation principlesby independent outside petroleum engineers. For the year ended December 31, 2008, these reservesestimates were audited by LaRoche Petroleum Consultants, Ltd. For the years ended December 31, 2009and 2010, the Company’s reserves estimates were audited by Netherland, Sewell & Associates, Inc.

The Company’s net ownership in estimated quantities of proved oil and natural gas reserves andchanges in net proved reserves are summarized as follows. All of the Company’s oil and natural gasreserves are attributable to properties located in the United States. The estimated reserves shown below arefor proved reserves only and do not include any value for unproved reserves classified as probable orpossible reserves that might exist for these properties, nor do they include any consideration that could beattributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. Inthe tables presented throughout this section, oil is converted to gas equivalent using the ratio of one barrel ofoil, condensate or natural gas liquids to 6 Mcf (thousand standard cubic feet) of natural gas.

F-42



December 31, 2010, 2009 and 2008


Net Proved Reserves

Oil GasGas

Equivalent

(Mbbl) (MMcf) (MMcfe)

Proved Developed and Proved Undeveloped Reserves

Total at December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136 33,280 34,098Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . 12 (17,492) (17,426)Extensions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . 20 6,493 6,614Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (37) (3,085) (3,307)

Total at December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131 19,196 19,979Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . (13) (811) (883)Extensions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . 15 50,367 50,454Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (30) (4,823) (5,002)

Total at December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103 63,929 64,548Revisions of prior estimates . . . . . . . . . . . . . . . . . . . . . . . . 66 874 1,265Extensions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . 16 71,009 71,107Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (33) (8,400) (8,597)

Total at December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152 127,412 128,323

Proved Developed Reserves

December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129 14,271 15,042December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131 19,196 19,979December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103 25,369 25,988December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152 43,143 44,054

Proved Undeveloped Reserves

December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 19,009 19,056December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – –December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 38,560 38,560December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 84,269 84,269

The following is a discussion of the changes in the Company’s proved oil and natural gas reservesestimates for the years ended December 31, 2010, 2009 and 2008.

The Company’s proved oil and natural gas reserves increased to 128.3 Bcfe at December 31, 2010from 64.5 Bcfe at December 31, 2009. The Company increased its proved oil and natural gas reserves by72.4 Bcfe and produced 8.6 Bcfe during the year ended December 31, 2010, resulting in a net gain of 63.8Bcfe. A total of 71.1 Bcfe of the increase in proved oil and gas reserves was a result of extensions anddiscoveries during the year, almost all of which was attributable to drilling operations in the Haynesvilleshale play in north Louisiana. A total of 1.3 Bcfe of the increase in proved oil and natural gas reserves wasattributable to revisions of previous estimates, representing the net impact of small changes in priorestimates of proved reserves on a well-by-well basis. The Company’s proved developed oil and natural gas

F-43



December 31, 2010, 2009 and 2008


reserves increased to 44.1 Bcfe at December 31, 2010 from 26.0 Bcfe at December 31, 2009, primarily dueto proved developed reserves added as a result of drilling operations in the Haynesville shale play. AtDecember 31, 2010, the Company’s proved reserves were made up of approximately 99% natural gas and1% oil.

The Company’s proved oil and natural gas reserves increased to 64.5 Bcfe at December 31, 2009 from20.0 Bcfe at December 31, 2008. The Company increased its proved oil and natural gas reserves by 49.5Bcfe and produced 5.0 Bcfe during the year ended December 31, 2009, resulting in a net gain of 44.5 Bcfe.The Company added 50.4 Bcfe in proved oil and natural gas reserves as a result of extensions anddiscoveries during the year, almost all of which was attributable to drilling operations in the Haynesvilleshale play in north Louisiana. The Company’s oil and natural gas reserves decreased by 0.9 Bcfe during theyear as a result of revisions to previous estimates, representing the net impact of small changes in priorestimates of proved reserves on a well-by-well basis. The Company’s proved developed oil and natural gasreserves increased to 26.0 Bcfe at December 31, 2009 from 20.0 Bcfe at December 31, 2008, primarily dueto proved developed reserves added as a result of drilling operations in the Haynesville shale play. AtDecember 31, 2009, the Company’s proved reserves were made up of approximately 99% natural gas and1% oil.

The Company’s proved oil and natural gas reserves decreased to 20.0 Bcfe at December 31, 2008 from34.1 Bcfe at December 31, 2007. The Company produced 3.3 Bcfe during the year and added 6.6 Bcfe inproved oil and natural gas reserves as a result of extensions and discoveries, almost all of which wasattributable to drilling operations in the Cotton Valley play in north Louisiana. The Company’s oil andnatural gas reserves decreased by 17.4 Bcfe during the year due to revisions of previous estimates, primarilyattributable to a sharp decline in natural gas prices during the latter half of 2008, causing the Company toremove all proved undeveloped reserves (primarily in the Cotton Valley play) from its total proved reservesestimates. The Company’s proved developed oil and natural gas reserves increased to 20.0 Bcfe atDecember 31, 2008 from 14.3 Bcfe at December 31, 2007, primarily due to proved developed reservesadded as a result of drilling operations in the Cotton Valley play. At December 31, 2008, the Company’sproved reserves were made up of approximately 96% natural gas and 4% oil.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil andNatural Gas Reserves

The standardized measure of discounted future net cash flows relating to proved oil and natural gasreserves is not intended to provide an estimate of the replacement cost or fair market value of theCompany’s oil and natural gas properties. An estimate of fair market value would also take into account,among other things, the recovery of reserves not presently classified as proved, anticipated future changes inprices and costs, potential improvements in industry technology and operating practices, the risks inherentin reserves estimates and perhaps different discount rates.

As noted previously, for the period January through December 2010, average oil and natural gas priceswere $75.96 per barrel and $4.376 per MMBtu (million British thermal units), respectively. For the periodJanuary through December 2009, average oil and natural gas prices were $57.65 per barrel and $3.866 per

F-44



December 31, 2010, 2009 and 2008


MMBtu, respectively. Prior to 2009, SEC guidelines for estimating and reporting oil and natural gasreserves required using commodity prices at the last day of the year. For 2008, year-end oil and natural gasprices were $41.00 per barrel and $5.71 per MMBtu, respectively.

Future net cash flows were computed by applying these oil and natural gas prices, adjusted for allassociated transportation costs, gravity and energy content, and regional price differentials, to year-endquantities of proved oil and natural gas reserves and accounting for any future production and developmentcosts associated with producing these reserves; neither prices nor costs were escalated with time in thesecomputations.

Future income taxes were computed by applying the statutory tax rate to the excess of future net cashflows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Taxcredits and net operating loss carryforwards available to the Company were also considered in thecomputation of future income taxes. Future net cash flows after income taxes were discounted using a 10%annual discount rate to derive the standardized measure of discounted future net cash flows.

The following table presents the standardized measure of discounted future net cash flows relating toproved oil and natural gas reserves (in thousands) for the years ended December 31, 2010, 2009 and 2008.


2010 2009 2008

Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 470,386 $219,410 $113,940Future production costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (107,183) (55,513) (37,871)Future development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (107,277) (35,788) (3,330)Future income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . (35,352) (15,805) (3,406)

Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 220,574 112,304 69,33310% annual discount for estimated timing of cash flows . . . . . (109,497) (47,243) (26,079)

Standardized measure of discounted future net cashflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 111,077 $ 65,061 $ 43,254

F-45



December 31, 2010, 2009 and 2008


The following table summarizes the changes in the standardized measure of discounted future net cashflows relating to proved oil and natural gas reserves (in thousands) for the years ended December 31, 2010,2009 and 2008.


2010 2009 2008

Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 65,061 $ 43,254 $ 53,934Net changes in sales and transfer prices and in production (lifting) costs

related to future production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,632 (10,433) (18,682)Changes in estimated future development costs . . . . . . . . . . . . . . . . . . . . . (36,821) (17,502) 40,902Sales and transfers of oil and gas produced during the period . . . . . . . . . . (26,776) (13,236) (24,339)Net change due to extensions and discoveries . . . . . . . . . . . . . . . . . . . . . . 94,265 70,361 15,257Net change due to purchase of minerals in place . . . . . . . . . . . . . . . . . . . . – – –Net changes due to revisions in estimates of reserves quantities . . . . . . . . 1,676 (1,232) (40,197)Previously estimated development costs incurred during the period . . . . . 7,125 (590) 9,108Accretion of discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,036 4,317 5,621Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,035 (3,068) 3,713Net change in income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (9,156) (6,810) (2,063)

Standardized measure of discounted future net cash flows . . . . . . . . . $111,077 $ 65,061 $ 43,254

NOTE 17 — SUBSEQUENT EVENTS

Subsequent events have been evaluated by the Company through August 12, 2011, the date thefinancial statements were available to be issued.

In January 2011, the Company sold 53,772 shares of Class A common stock at $11.00 per share andreceived net proceeds of $584,918 in conclusion of its October 2010 through January 2011 private offering(see Note 9).

Between January and July 2011, the Company committed to participate in 36 gross (approximately 1.1net) non-operated wells in the Haynesville shale in north Louisiana. The Company has working interestsranging from 0.2% to 18.7% in these wells, and most of these wells are already in progress. The Company’sminimum outstanding capital commitments for its participation in these non-operated Haynesville wells areapproximately $3.2 million, assuming that all these wells are drilled and completed by the operators.

In May and July 2011, the Company entered into two drilling rig contracts to explore and develop itsEagle Ford acreage in south Texas. The Company expects the first rig will begin drilling operations on itsacreage in August 2011, with the second rig beginning drilling operations on its acreage in October 2011.Both contracts are for a term of six months. Should the Company elect to terminate both contracts prior toinitiating drilling operations, and if the drilling contractor were unable to secure work for both rigs prior tothe end of their respective contract terms, the Company would incur an aggregate termination obligation ofapproximately $5.5 million.

F-46



December 31, 2010, 2009 and 2008

NOTE 17 — SUBSEQUENT EVENTS — Continued

In May 2011, the Company entered into three additional costless collar transactions to mitigate its risksassociated with fluctuations in natural gas prices. The following table summarizes these natural gas hedgingcontracts.


PriceFloor

PriceCeiling

(MMBtu/month)

($/MMBtu) ($/MMBtu)

Natural Gas . . . . . . . . . . . . . . . 07/01/2011 - 12/31/2012 300,000 4.50 5.60Natural Gas . . . . . . . . . . . . . . . 07/01/2011 - 07/31/2013 150,000 4.50 5.75Natural Gas . . . . . . . . . . . . . . . 01/01/2012 - 12/31/2012 150,000 4.25 6.17

Between March and July 2011, the Company acquired leasehold interests in approximately 6,274 grossand 4,802 net acres in Karnes, DeWitt, Wilson and Gonzales Counties, Texas. This acreage is prospectivefor the Eagle Ford shale, an emerging oil and natural gas play in south Texas. The Company paidapproximately $31.5 million in cash and agreed to additional drilling and completion incentives to the sellerin the form of back-in interests and future participation rights to acquire this acreage.

In May 2011, the Company amended and restated its Credit Agreement with Comerica Bank. Thisamendment increased the borrowing base under the Credit Agreement from $55,000,000 to $80,000,000and amended the debt to EBITDA ratio (defined as total debt outstanding divided by a rolling four-quarterEBITDA) to 4.00 or less at all times. Under the amended and restated Credit Agreement, the Company alsoentered into a term loan for $25,000,000 with a maturity date of December 31, 2011. Proceeds from theterm loan were used in partial payment of the acreage acquisition described above; the remaining fundsrequired for the acreage acquisition were provided under the borrowing base. The term loan bears interest atLIBOR plus 5.00%, and while the term loan is outstanding, the Company’s other borrowings under theCredit Agreement bear interest at the maximum rate of LIBOR plus 1.875%. At August 12, 2011, includingthe term loan, the Company had $85,000,000 of outstanding borrowings under the Credit Agreement and$375,000 in letters of credit secured by the Credit Agreement. All borrowings under the Credit Agreementare Eurodollar loans. The term loan bears interest at approximately 5.3%, and the other borrowings bearinterest at approximately 2.1%.

In June 2011, the Company awarded bonuses to certain of its current employees, but not including anyof its executive officers, in the aggregate amount of $1,240,000. These bonuses will be payable in a lumpsum to each of these employees in June 2014, provided each continues to remain an employee in goodstanding with the Company at that time.

F-47


CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

Contents

Condensed Consolidated Financial Statements

Condensed Consolidated Balance Sheets at September 30, 2011 (Unaudited) and December 31,2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-49

Condensed Consolidated Statements of Operations for the three and nine months endedSeptember 30, 2011 and 2010 (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-50

Condensed Consolidated Statement of Shareholders’ Equity for the nine months endedSeptember 30, 2011 (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-51

Condensed Consolidated Statements of Cash Flows for the nine months ended September 30,2011 and 2010 (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-52

Notes to Condensed Consolidated Financial Statements (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . F-53

F-48


CONDENSED CONSOLIDATED BALANCE SHEETS

September 30,2011

December 31,2010

(Unaudited)ASSETSCurrent assets

Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7,767,976 $ 21,059,519Certificates of deposit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,085,313 2,349,313Accounts receivable

Oil and natural gas revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,303,439 6,514,122Joint interest billings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,547,952 2,042,999Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,208,102 3,091,372

Derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,890,628 4,144,411Lease and well equipment inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,737,393 1,423,197Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,636,401 1,876,358

Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32,177,204 42,501,291Property and equipment, at cost

Oil and natural gas properties, full-cost methodEvaluated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 345,200,274 255,408,993Unproved and unevaluated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 184,008,220 172,451,449

Other property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,336,739 14,035,010Less accumulated depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . . . (196,266,352) (138,014,986)

Net property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 350,278,881 303,880,466Other assets

Derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 787,484 –

Total other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 787,484 –

Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 383,243,569 $ 346,381,757

LIABILITIES AND SHAREHOLDERS’ EQUITYCurrent liabilities

Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,281,357 $ 12,166,938Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,095,056 14,658,546Royalties payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,529,719 982,270Advances from joint interest owners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 722,843Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 1,473,619Borrowings under Credit Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,000,000 –Dividends payable — Class B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68,713 68,713Other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126,829 23,577

Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50,101,674 30,096,506Long-term liabilities

Borrowings under Credit Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60,000,000 25,000,000Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,305,407 3,695,017Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 5,432,638Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 298,139 280,453

Total long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64,603,546 34,408,108Commitments and contingencies (Note 8)

Shareholders’ equityCommon stock — Class A, $0.01 par value, 80,000,000 shares authorized;

42,907,843 and 42,749,820 shares issued; and 41,728,668 and 41,570,645 sharesoutstanding, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 429,078 427,498

Common stock — Class B, $0.01 par value, 2,000,000 shares authorized; 1,030,700shares issued and outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,307 10,307

Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 263,932,648 263,341,642Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,931,138 28,862,518Treasury stock, at cost, 1,179,175 shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (10,764,822) (10,764,822)

Total shareholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 268,538,349 281,877,143

Total liabilities and shareholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 383,243,569 $ 346,381,757


F-49


CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

Three Months EndedSeptember 30,


2011 2010 2011 2010

RevenuesOil and natural gas revenues . . . . . . . . . . . . . . . . . . $17,446,638 $ 8,454,725 $ 52,008,788 $25,182,143Realized gain on derivatives . . . . . . . . . . . . . . . . . . 1,435,340 1,172,040 4,237,540 2,988,000Unrealized gain on derivatives . . . . . . . . . . . . . . . . 2,870,086 2,540,813 1,533,701 5,812,563

Total revenues . . . . . . . . . . . . . . . . . . . . . 21,752,064 12,167,578 57,780,029 33,982,706Expenses

Production taxes and marketing . . . . . . . . . . . . . . . 1,847,607 414,928 4,800,963 1,234,734Lease operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,064,657 1,385,668 5,638,766 3,800,780Depletion, depreciation and amortization . . . . . . . . 7,288,091 3,867,913 22,578,268 10,931,543Accretion of asset retirement obligations . . . . . . . . 61,597 38,635 157,891 106,590Full-cost ceiling impairment . . . . . . . . . . . . . . . . . . – – 35,673,098 –General and administrative . . . . . . . . . . . . . . . . . . . 3,682,920 2,273,227 9,394,964 6,792,902

Total expenses . . . . . . . . . . . . . . . . . . . . 14,944,872 7,980,371 78,243,950 22,866,549

Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . 6,807,192 4,187,207 (20,463,921) 11,116,157Other income (expense)

Interest and other income . . . . . . . . . . . . . . . . 81,950 78,621 247,547 300,348Interest expense . . . . . . . . . . . . . . . . . . . . . . . (170,880) – (460,699) –

Total other (expense) income . . . . . . . . . (88,930) 78,621 (213,152) 300,348

Income (loss) before incometaxes . . . . . . . . . . . . . . . . . . . . . . 6,718,262 4,265,828 (20,677,073) 11,416,505

Income tax (benefit) provisionCurrent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 (1,410,608) (45,576) (1,410,608)Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 2,994,983 (6,906,257) 5,453,908

Total income tax (benefit) provision . . . 60 1,584,375 (6,951,833) 4,043,300

Net income (loss) . . . . . . . . . . . . . . $ 6,718,202 $ 2,681,453 $(13,725,240) $ 7,373,205


Class A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.15 $ 0.07 $ (0.33) $ 0.18

Class B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.22 $ 0.14 $ (0.13) $ 0.38

DilutedClass A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.15 $ 0.07 $ (0.33) $ 0.18

Class B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.22 $ 0.14 $ (0.13) $ 0.38

Weighted average common shares outstandingBasic

Class A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,720,571 39,558,504 41,670,847 39,849,438Class B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,030,700 1,030,700 1,030,700 1,030,700

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42,751,271 40,589,204 42,701,547 40,880,138

DilutedClass A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,848,245 39,572,930 41,670,847 39,911,491Class B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,030,700 1,030,700 1,030,700 1,030,700

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42,878,945 40,603,630 42,701,547 40,942,191


F-50


CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY(UNAUDITED)

For the nine months ended September 30, 2011

Common stockAdditional

paid-incapital

Retainedearnings Total

Class A Class B Treasury stock

Shares Amount Shares Amount Shares Amount

Balance at January 1,2011 . . . . . . . . . . . . . . . 42,749,820 $427,498 1,030,700 $10,307 $263,341,642 $ 28,862,518 1,179,175 $(10,764,822) $281,877,143

Issuance of Class Acommon stock . . . . . . . 53,772 538 – – 590,954 – – – 591,492

Additional cost to issueequity . . . . . . . . . . . . . . – – – – (1,011,708) – – – (1,011,708)

Issuance of Class Acommon stock to

Board members andadvisors . . . . . . . . 11,250 113 – – 124,387 – – – 124,500

Stock options granted . . . – – – – 15,293 – – – 15,293Stock options

exercised . . . . . . . . . . . 93,001 929 – – 836,080 – – – 837,009Restricted stock vested . . – – – – 36,000 – – – 36,000Class B dividends

declared . . . . . . . . . . . . – – – – – (206,140) – – (206,140)Current period net loss . . – – – – – (13,725,240) – – (13,725,240)

Balance at September 30,2011 . . . . . . . . . . . . . . . 42,907,843 $429,078 1,030,700 $10,307 $263,932,648 $ 14,931,138 1,179,175 $(10,764,822) $268,538,349


F-51


CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


2011 2010

Operating activitiesNet (loss) income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (13,725,240) $ 7,373,205Adjustments to reconcile net (loss) income to net cash provided by

operating activitiesUnrealized (gain) on derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . (1,533,701) (5,812,563)Depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . 22,578,268 10,931,543Accretion of asset retirement obligations . . . . . . . . . . . . . . . . . . . 157,891 106,590Full-cost ceiling impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35,673,098 –Stock option and grant expense . . . . . . . . . . . . . . . . . . . . . . . . . . . 854,726 466,610Restricted stock grants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36,000 24,750Deferred income tax (benefit) provision . . . . . . . . . . . . . . . . . . . . (6,906,257) 5,453,908Changes in operating assets and liabilities

Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,410,999) 3,749,739Lease and well equipment inventory . . . . . . . . . . . . . . . . . . . (784) (7,454)Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 239,957 (1,145,593)Accounts payable, accrued liabilities and other liabilities . . . (2,359,387) (589,800)Royalties payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,547,449 313,160Advances from joint interest owners . . . . . . . . . . . . . . . . . . . (722,843) 550,000Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,056 (23,577)

Net cash provided by operating activities . . . . . . . . . . . 34,443,234 21,390,518Investing activities

Oil and natural gas properties capital expenditures . . . . . . . . . . . . . . . . (104,733,188) (86,031,353)Expenditures for other property and equipment . . . . . . . . . . . . . . . . . . (3,303,007) (933,511)Purchases of certificates of deposit . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,721,000) (3,739,000)Sales of certificates of deposit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,985,000 11,985,468

Net cash used in investing activities . . . . . . . . . . . . . . . (107,772,195) (78,718,396)Financing activities

Borrowings under Credit Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . 60,000,000 –Proceeds from issuance of common stock . . . . . . . . . . . . . . . . . . . . . . . 591,492 99,000Cost to issue equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,184,943) –Proceeds from stock options exercised . . . . . . . . . . . . . . . . . . . . . . . . . 837,009 823,375Payment of dividends — Class B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (206,140) (206,140)Purchase of treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – (9,000,000)

Net cash provided by (used in) financing activities . . . 60,037,418 (8,283,765)

Decrease in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (13,291,543) (65,611,643)Cash and cash equivalents at beginning of period . . . . . . . . . . . . . . . . . . . . . 21,059,519 104,229,709

Cash and cash equivalents at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7,767,976 $ 38,618,066


F-52


NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)

September 30, 2011

NOTE 1 — NATURE OF OPERATIONS

Matador Resources Company (“Matador” or “Company”) is an independent energy company engagedin the exploration, development, acquisition and production of oil and natural gas resources in theUnited States, with a particular emphasis on oil and natural gas shale plays and other unconventionalresources. Matador’s current operations are located primarily in the Haynesville shale play in northLouisiana and east Texas and the Eagle Ford shale play in south Texas; these plays are key elements of theCompany’s growth strategy. In addition to these primary operating areas, Matador has significant acreagepositions in southeast New Mexico and west Texas and in southwest Wyoming and adjacent areas in Utahand Idaho where the Company continues to identify new oil and natural gas prospects.

On November 22, 2010, Matador Resources Company formed a wholly-owned subsidiary, MatadorHoldco, Inc. Pursuant to the terms of the corporate reorganization that was completed on August 9, 2011,Matador Resources Company changed its corporate name to MRC Energy Company and Matador Holdco,Inc. changed its corporate name to Matador Resources Company. As a part of this reorganization, MRCEnergy Company became a wholly owned subsidiary of Matador Resources Company. The accompanyingunaudited condensed consolidated financial statements include the accounts of Matador ResourcesCompany and its wholly owned subsidiary, MRC Energy Company, as well as the accounts of MRC EnergyCompany’s four wholly owned subsidiaries, Matador Production Company, Longwood Gathering andDisposal Systems GP, Inc., MRC Permian Company and MRC Rockies Company, and the accounts ofLongwood Gathering and Disposal Systems, LP.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Interim Financial Statements, Basis of Presentation, Consolidation and Significant Estimates

The unaudited condensed consolidated financial statements of Matador and its subsidiaries have beenprepared in accordance with generally accepted accounting principles in the United States of America(“U.S. GAAP”), but do not include all of the information and footnotes required for complete financialstatements. All intercompany accounts and transactions have been eliminated in consolidation. Inmanagement’s opinion, these interim unaudited condensed consolidated financial statements include alladjustments of a normal recurring nature necessary for a fair presentation of the Company’s consolidatedfinancial position as of September 30, 2011, consolidated results of operations for the three and nine monthsended September 30, 2011 and 2010, consolidated shareholders’ equity for the nine months endedSeptember 30, 2011 and consolidated cash flows for the nine months ended September 30, 2011 and 2010.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at yearend and the results for the interim periods shown in this report are not necessarily indicative of results to beexpected for the full year due in part to volatility in oil and natural gas prices, global economic and financialmarket conditions, interest rates, access to sources of liquidity, estimates of reserves, drilling risks,geological risks, transportation restrictions, oil and natural gas supply and demand, market competition andinterruptions of production. These interim unaudited condensed consolidated financial statements should beread in conjunction with the Company’s audited consolidated financial statements and notes thereto for theyear ended December 31, 2010.

F-53


NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED) — CONTINUED

September 30, 2011


The preparation of financial statements in conformity with U.S. GAAP requires management to makeestimates and assumptions that affect the amounts reported in the financial statements and accompanyingnotes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at thedate of the financial statements and the reported amounts of revenues and expenses during the reportingperiod. The Company’s consolidated financial statements are based on a number of significant estimates,including accruals for oil and natural gas revenues, accrued assets and liabilities primarily related to oil andnatural gas operations, stock-based compensation, valuation of derivative instruments and oil and naturalgas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basisfor the calculations of depletion and impairment of oil and natural gas properties, as well as estimates ofasset retirement obligations and certain tax accruals. While the Company believes its estimates arereasonable, changes in facts and assumptions or the discovery of new information may result in revisedestimates. Actual results could differ from these estimates.


The Company uses the full-cost method of accounting for its investments in oil and natural gasproperties. Under this method of accounting, all costs associated with the acquisition, exploration anddevelopment of oil and natural gas properties and reserves, including unproved and unevaluated propertycosts, are capitalized as incurred and accumulated in a single cost center representing the Company’sactivities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs,geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling bothproductive and non-productive wells, capitalized interest on qualifying projects and general andadministrative expenses directly related to exploration and development activities, but do not include anycosts related to production, selling or general corporate administrative activities. The Company capitalized$1,329,969 and $1,065,908 of its general and administrative costs for the nine months ended September 30,2011 and 2010, respectively. The Company capitalized $755,733 of its interest expense for the nine monthsended September 30, 2011. For the period ended September 30, 2010, the company had no outstandingborrowings and no interest expense.

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costsless related deferred income taxes or the cost center ceiling, with any excess above the cost center ceilingcharged to operations as a full-cost ceiling impairment. The cost center ceiling is defined as the sum of(a) the present value discounted at 10 percent of future net revenues of proved oil and natural gas reserves,plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost orestimated fair value of unproved and unevaluated properties included in the costs being amortized, if any,less (d) income tax effects related to differences between the book and tax basis of the properties involved.Future net revenues from proved non-producing and proved undeveloped reserves are reduced by theestimated costs for developing these reserves. The fair value of the Company’s derivative instruments is notincluded in the ceiling test computation as the Company does not designate these instruments as hedgeinstruments for accounting purposes.

F-54



September 30, 2011


The estimated present value of after-tax future net cash flows from proved oil and natural gas reservesis highly dependent on the commodity prices used in these estimates. These estimates are determined inaccordance with guidelines established by the Securities and Exchange Commission (“SEC”) for estimatingand reporting oil and natural gas reserves. Under these guidelines, oil and natural gas reserves are estimatedusing then-current operating and economic conditions, with no provision for price and cost escalations infuture periods except by contractual arrangements.

Beginning December 31, 2009, the commodity prices used to estimate oil and natural gas reserves arebased on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for theprevious 12-month period. For the period October 1, 2010 through September 30, 2011, these average oiland natural gas prices were $91.00 per barrel and $4.158 per MMBtu (million British thermal units),respectively. In estimating the present value of after-tax future net cash flows from proved oil and naturalgas reserves, the average oil prices were adjusted by property for quality, transportation fees and regionalprice differentials, and the average natural gas prices were adjusted by property for energy content,transportation fees and regional price differentials. At September 30, 2011, the Company’s oil and naturalgas reserves estimates were prepared by the Company’s engineering staff in accordance with guidelinesestablished by the SEC and then audited for their reasonableness and conformance with SEC guidelines byNetherland, Sewell & Associates, Inc., independent petroleum engineers.

Using the average commodity prices, as adjusted, to determine the Company’s estimated proved oiland natural gas reserves at September 30, 2011, the Company’s net capitalized costs did not exceed the costcenter ceiling. As a result, the Company recorded no impairment to its net capitalized costs and nocorresponding charge to its consolidated statement of operations for the three months ended September 30,2011. At March 31, 2011, the Company’s net capitalized costs exceeded the cost center ceiling by$22,989,866. The Company recorded an impairment charge of $35,673,098 to its net capitalized costs and adeferred income tax credit of $12,683,232 related to the cost center ceiling limitation at March 31, 2011.These charges are reflected in the Company’s unaudited condensed consolidated statement of operations forthe nine months ended September 30, 2011. The Company recorded no impairment to its net capitalizedcosts and no corresponding charge to its unaudited condensed consolidated statement of operations for thethree and nine months ended September 30, 2010. Changes in oil and natural gas production rates, reservesestimates, future development costs and other factors will determine the Company’s actual ceiling testcomputation and impairment analyses in future periods.

As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the netcarrying value of the Company’s assets on its balance sheet, as well as the corresponding shareholders’equity, but it has no impact on the Company’s net cash flows as reported.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production methodbased upon production and estimates of proved reserves quantities. Unproved and unevaluated propertycosts are excluded from the amortization base used to determine depletion. Unproved and unevaluatedproperties are assessed for possible impairment on a periodic basis based upon changes in operating or

F-55



September 30, 2011


economic conditions. This assessment includes consideration of the following factors, among others: theassignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term,and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties areimmediately included in the amortization base. Dry holes are included in the amortization base immediatelyupon determination that the well is not productive.

Income Taxes

The Company files a United States federal income tax return and several state tax returns, a number ofwhich remain open for examination. The tax years open for examination for the federal tax return are 2007,2008, 2009 and 2010. The tax years open for examination by the state of Texas are 2008, 2009 and 2010.The tax years open for examination by the state of New Mexico are 2008, 2009 and 2010. The tax yearsopen for examination by the state of Louisiana are 2007, 2008, 2009 and 2010. As of December 30, 2011,the Company’s 2007, 2008 and 2009 income and franchise tax returns are under examination by the state ofLouisiana. As a result of preliminary findings received by the Company from the state of Louisiana, theCompany has recorded an income tax refund of $45,636, a franchise tax assessment of $91,995 and anassociated interest expense of $12,429 for the three and nine months ended September 30, 2011.

The Company accounts for income taxes using the asset and liability approach for financial accountingand reporting. The Company evaluates the probability of realizing the future benefits of its deferred taxassets and provides a valuation allowance for the portion of any deferred tax assets where the likelihood ofrealizing an income tax benefit in the future does not meet the more likely than not criteria for recognition.

As noted previously, the Company recorded an impairment charge of $22,989,866 to its net capitalizedcosts, net of a deferred income tax credit of $12,683,232 related to the full-cost ceiling limitation atMarch 31, 2011. This deferred income tax credit exceeded the Company’s deferred tax liabilities atMarch 31, 2011. As a result, the Company established a valuation allowance as of March 31, 2011 andretains a valuation allowance in the amount of $823,654 as of September 30, 2011 due to uncertaintiesregarding the future realization of its deferred tax assets. The Company will continue to assess the valuationallowance on a periodic basis and to the extent the Company determines that the allowance is no longerrequired, the tax benefit of the remaining deferred tax assets will be recognized in the future.

The Company had a net loss for the nine months ended September 30, 2011 and its effective tax ratefor the nine months ended September 30, 2010 was 35.42%. Total income tax expense for the nine monthsended September 30, 2011 and 2010 differed from the amounts computed by applying the U.S. statutory taxrates to income before income taxes due primarily to state taxes and the impact of permanent differencesbetween book and taxable income.

Earnings Per Common Share

The Company reports basic earnings per common share, which excludes the effect of potentiallydilutive securities, and diluted earnings per common share, which includes the effect of all potentiallydilutive securities, unless their impact is anti-dilutive.

F-56



September 30, 2011


The Company has issued two classes of common stock, Class A and Class B. The holders of the ClassB shares are entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of fundslegally available for the payment of dividends. These dividends are accrued and paid quarterly. Dividendsdeclared during the three and nine months ended September 30, 2011 and 2010 totaled $68,713 and$206,140, respectively, in each period. As of September 30, 2011, the Company has not paid any dividendsto holders of the Class A shares.

The following are reconciliations of the numerators and denominators used to compute the Company’sbasic and diluted distributed and undistributed earnings (loss) per common share as reported for the threeand nine months ended September 30, 2011 and 2010.



2011 2010 2011 2010

Net income (loss) — numeratorNet income (loss) . . . . . . . . . . . . . . . . . . . . . . $ 6,718,202 $ 2,681,453 $(13,725,240) $ 7,373,205Less dividends to Class B shareholders —

distributed earnings . . . . . . . . . . . . . . . . . . (68,713) (68,713) (206,140) (206,140)

Undistributed earnings (loss) . . . . . . . . . $ 6,649,489 $ 2,612,740 $(13,931,380) $ 7,167,065

Weighted average common sharesoutstanding — denominatorBasic

Class A . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,720,571 39,558,504 41,670,847 39,849,438Class B . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,030,700 1,030,700 1,030,700 1,030,700

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42,751,271 40,589,204 42,701,547 40,880,138

DilutedClass A

Weighted average common sharesoutstanding for basic earnings pershare . . . . . . . . . . . . . . . . . . . . . . . . . . 41,720,571 39,558,504 41,670,847 39,849,438

Dilutive effect of options . . . . . . . . . . . . 127,674 14,426 – 62,053

Class A weighted average commonshares outstanding — diluted . . . . . 41,848,245 39,572,930 41,670,847 39,911,491

Class BWeighted average common shares

outstanding — no associated dilutiveshares . . . . . . . . . . . . . . . . . . . . . . . . . 1,030,700 1,030,700 1,030,700 1,030,700

Total diluted weighted averagecommon shares outstanding . . . . . . 42,878,945 40,603,630 42,701,547 40,942,191

F-57



September 30, 2011




2011 2010 2011 2010


Class ADistributed earnings . . . . . . . . . . . . $ – $ – $ – $ –Undistributed earnings (loss) . . . . . $0.15 $0.07 $(0.33) $0.18

Total . . . . . . . . . . . . . . . . . . . . $0.15 $0.07 $(0.33) $0.18

Class BDistributed earnings . . . . . . . . . . . . $0.07 $0.07 $ 0.20 $0.20Undistributed earnings (loss) . . . . . $0.15 $0.07 $(0.33) $0.18

Total . . . . . . . . . . . . . . . . . . . . $0.22 $0.14 $(0.13) $0.38

DilutedClass A

Distributed earnings . . . . . . . . . . . . $ – $ – $ – $ –Undistributed earnings (loss) . . . . . $0.15 $0.07 $(0.33) $0.18

Total . . . . . . . . . . . . . . . . . . . . $0.15 $0.07 $(0.33) $0.18

Class BDistributed earnings . . . . . . . . . . . . $0.07 $0.07 $ 0.20 $0.20Undistributed earnings (loss) . . . . . $0.15 $0.07 $(0.33) $0.18

Total . . . . . . . . . . . . . . . . . . . . $0.22 $0.14 $(0.13) $0.38

A total of 1,024,500 options to purchase shares of the Company’s Class A common stock wereexcluded from the calculations above for the nine months ended September 30, 2011 because their effectswere anti-dilutive. These options were included in the calculations above for the three months endedSeptember 30, 2011.

Fair Value Measurements

The Company measures and reports certain assets and liabilities on a fair value basis. Fair value is theprice that would be received to sell an asset or paid to transfer a liability in an orderly transaction betweenmarket participants at the measurement date (exit price). The Company follows Financial AccountingStandards Board (“FASB”) guidance establishing a fair value hierarchy that prioritizes the inputs tovaluation methods used to measure fair value.

The carrying amounts reported on the unaudited condensed consolidated balance sheet for cash andcash equivalents, certificates of deposit, accounts receivable, prepaid expenses, accounts payable, accrued

F-58



September 30, 2011


liabilities, royalties payable, advances from joint interest owners, dividends payable and other liabilitiesapproximate their fair values, due to the short-term maturity of these instruments.

At September 30, 2011, the carrying value of $85,000,000 for the Company’s borrowings (both currentand long-term liabilities) under its $150,000,000 senior secured revolving credit agreement (the “CreditAgreement”) on the unaudited condensed consolidated balance sheet is approximately fair value as it issubject to short-term floating interest rates that approximate the rates available to the Company at the time.


Fair Value. In May 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-04,Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP andIFRS (“ASU 2011-04”). ASU 2011-04 amends Accounting Standards Codification (“ASC”) 820, FairValue Measurements (“ASC 820”), providing a consistent definition and measurement of fair value, as wellas similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards.ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fairvalue measurements and expands the ASC 820 disclosure requirements, particularly for Level 3 fair valuemeasurements. The adoption of ASU 2011-04 is not expected to have a material effect on the Company’sconsolidated financial statements, but may require certain additional disclosures. The amendments in ASU2011-04 are to be applied prospectively. For public entities, the amendments are effective during interimand annual periods beginning after December 15, 2011.

NOTE 3 — ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in the Company’s asset retirement obligations for the ninemonths ended September 30, 2011.

Beginning asset retirement obligations . . . . . . . . . . . . . $3,695,017Liabilities incurred during period . . . . . . . . . . . . . . . . . 535,251Liabilities settled during period . . . . . . . . . . . . . . . . . . . (82,752)Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157,891

Ending asset retirement obligations . . . . . . . . . . . . . . . . $4,305,407

NOTE 4 — CREDIT AGREEMENT

In March 2008, the Company entered into the Credit Agreement with Comerica Bank asAdministrative Agent, Syndication and Documentation Agent and Issuing Lender. The Credit Agreement issecured by a significant portion of the Company’s oil and natural gas producing properties and by the equityinterests of all its subsidiaries. In addition, all obligations under the Credit Agreement are guaranteed by theCompany’s subsidiaries. The Credit Agreement matures in March 2013.

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September 30, 2011

NOTE 4 — CREDIT AGREEMENT — Continued

Borrowings under the Credit Agreement are limited to the lesser of $150,000,000 or the borrowingbase, which is determined by Comerica Bank semi-annually on May 1 and November 1. At September 30,2011, the borrowing base was $80,000,000. In May 2011, the Company amended and restated the CreditAgreement with Comerica Bank. This amendment increased the borrowing base under the CreditAgreement from $55,000,000 to $80,000,000 for revolving borrowings and amended the maximumleverage ratio (defined as total debt outstanding divided by a rolling four-quarter EBITDA) to 4.00 or less atall times. Under the amended and restated Credit Agreement, the Company also entered into a term loan for$25,000,000 with a maturity date of December 31, 2011, increasing total borrowings available under theCredit Agreement to $105,000,000 until the maturity of the term loan or a subsequent borrowing baseredetermination. The term loan bears interest at LIBOR plus 5.00%, and while the term loan is outstanding,the Company’s revolving borrowings under the Credit Agreement bear interest at the maximum rate ofLIBOR plus 1.875%.

The Company and Comerica Bank may each request an unscheduled redetermination of the borrowingbase one time during any 12-month period. The borrowing base is adjusted at the discretion of ComericaBank and is based in part on estimates of the Company’s proved oil and natural gas reserves, but also onexternal factors, such as Comerica Bank’s lending policies and estimates of future oil and natural gas prices,over which the Company has no control. In the event of a borrowing base increase, the Company pays a feeto Comerica Bank equal to 0.25% of the amount of the increase. If the borrowing base were to be less thanthe outstanding borrowings under the Credit Agreement at any time, the Company would be required toprovide additional collateral satisfactory in nature and value to Comerica Bank to increase the borrowingbase to an amount sufficient to cover such excess or to repay the deficit in equal installments over a periodof six months.

Borrowings under the Credit Agreement are subject to varying interest rates based on the totaloutstanding borrowings relative to the borrowing base and whether the loan is a Eurodollar loan or a baserate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin of 1.250% to1.875% based on the ratio of outstanding borrowings to the borrowing base. The Eurodollar rate for anyinterest period (one, two, three, six or twelve months as designated by the Company) is the rate equal toLIBOR, as published by Bloomberg Financial Markets Information Service or another source agreed uponby the Company and Comerica Bank, for deposits in United States dollars for a similar interest period. Thebase rate is the higher of the federal funds rate plus 1.0% or the annual rate of interest designated byComerica Bank as its prime rate. A commitment fee of 0.250% to 0.375% based on the unused portion ofthe borrowing base is paid quarterly in arrears.

Key financial covenants under the Credit Agreement require the Company to maintain (1) a minimumcurrent ratio (defined as total current assets plus availability under the Credit Agreement divided by totalcurrent liabilities) of 1.0 or greater at all times and (2) a maximum leverage ratio (defined as total debtoutstanding divided by a rolling four-quarter EBITDA) of 4.00 or less at all times. Other restrictivecovenants (1) prevent the Company from incurring other debt, subject to permitted exceptions, (2) prohibitthe Company from declaring and paying dividends, except on its Class B common stock, and (3) limit theaggregate amount of oil and natural gas production that can be hedged pursuant to commodity hedging

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September 30, 2011

NOTE 4 — CREDIT AGREEMENT — Continued

agreements and the maturity of those agreements. The Company was in compliance with all of ComericaBank’s covenants as of September 30, 2011 and December 31, 2010.

The Company obtained a written extension from Comerica Bank until July 15, 2011 to comply with acovenant under the Credit Agreement requiring submission of audited annual financial statements within120 days of the prior year end. The Company submitted its 2010 audited financial statements to ComericaBank prior to this July 15, 2011 deadline.

As of September 30, 2011, including the term loan, the Company had $85,000,000 of outstandingborrowings under the Credit Agreement (both current and long-term liabilities) and $1,262,934 in letters ofcredit secured by the Credit Agreement. All borrowings under the Credit Agreement were Eurodollar loans.The term loan bears interest at approximately 5.3% and the other borrowings bear interest at approximately2.2%.

NOTE 5 — COMMON STOCK

In October 2010, the Board of Directors approved and authorized the private offering and sale ofadditional shares of the Company’s Class A common stock at $11.00 per share in the period from October2010 through January 2011. As of December 31, 2010, the Company sold 1,868,427 shares and received netproceeds of $20,536,167. In January 2011, the Company sold an additional 53,772 shares as part of thisoffering and received net proceeds of $584,918.

NOTE 6 — DERIVATIVE FINANCIAL INSTRUMENTS

From time to time, the Company uses derivative financial instruments to hedge its exposure tocommodity price risk associated with natural gas prices. These instruments consist of put and call options inthe form of costless collars. The Company records derivative financial instruments on its balance sheet aseither an asset or a liability measured at fair value. The Company has elected not to apply hedge accountingfor its existing derivative financial instruments. As a result, the Company recognizes the change inderivative fair value between reporting periods currently in its consolidated statement of operations as anunrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined forinterim periods based on its counterparty’s valuation model. The Company verifies its counterparty’svaluation model annually for its reasonableness with an independent third-party valuation using observable,market-corroborated inputs.

The Company has entered into various costless collar transactions to mitigate its exposure to naturalgas price volatility, each with an established price floor and ceiling. For each calculation period, thespecified price for determining the realized gain or loss to the Company pursuant to any of thesetransactions is the settlement price for the NYMEX Henry Hub natural gas futures contract for the deliverymonth corresponding to the calculation period’s calendar month for the last day of that contract period.When the settlement price is below the price floor established by these collars, the Company receives fromComerica Bank, as counterparty, an amount equal to the difference between the settlement price and the

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September 30, 2011


price floor multiplied by the contract natural gas volume hedged. When the settlement price is above theprice ceiling established by these collars, the Company pays to Comerica Bank, as counterparty, an amountequal to the difference between the settlement price and the price ceiling multiplied by the contract naturalgas volume hedged. These transactions expose the Company to potential credit risk from its singlecounterparty, Comerica Bank; however, the Company believes that any credit risk posed is insignificant andis offset by the credit worthiness of Comerica Bank.

At September 30, 2011, the Company had various costless collar contracts open and in place, each witha specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling. Eachcontract is set to expire at varying times during 2011, 2012 and 2013. The Company had no hedgingcontracts in place with regard to any of its oil production at September 30, 2011.

The following table presents the fair value of the Company’s open natural gas costless collar contractsat September 30, 2011.


PriceFloor

PriceCeiling

September 30,2011

Fair Valueof Asset

(MMBtu/month)

($/MMBtu) ($/MMBtu)

Natural Gas . . . . . . . . . . . . . . 01/01/2010 - 12/31/2011 50,000 5.25 8.10 $ 218,361Natural Gas . . . . . . . . . . . . . . 01/01/2010 - 12/31/2011 50,000 5.50 7.65 255,695Natural Gas . . . . . . . . . . . . . . 01/01/2010 - 12/31/2011 50,000 5.00 8.65 181,214Natural Gas . . . . . . . . . . . . . . 01/01/2010 - 12/31/2011 50,000 5.50 7.70 255,695Natural Gas . . . . . . . . . . . . . . 01/01/2011 - 12/31/2011 90,000 5.50 7.85 460,251Natural Gas . . . . . . . . . . . . . . 07/01/2011 - 12/31/2012 300,000 4.50 5.60 2,322,636Natural Gas . . . . . . . . . . . . . . 07/01/2011 - 07/13/2013 150,000 4.50 5.75 1,356,034Natural Gas . . . . . . . . . . . . . . 01/01/2012 - 12/31/2012 150,000 4.25 6.17 628,226

Total . . . . . . . . . . . . . . . $5,678,112

Additional Disclosures about Derivative Financial Instruments

The following table summarizes the location and fair value of all derivative financial instrumentsrecorded in the consolidated balance sheets for the periods presented. These derivative financial instrumentsare not designated as hedging instruments.

Type of Instrument Location in Balance SheetSeptember 30,

2011December 31,

2010

Derivative InstrumentNatural Gas . . . . . . . . . . . . . . . . Current assets: Derivative instruments $4,890,628 $4,144,411

Other assets: Derivative instruments 787,484 –

Total . . . . . . . . . . . . . . . . . $5,678,112 $4,144,411

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September 30, 2011


The following table summarizes the location and fair value of all derivative financial instrumentsrecorded in the consolidated statements of operations for the periods presented. These derivative financialinstruments are not designated as hedging instruments.

Type of InstrumentLocation in

Statement of Operations



2011 2010 2011 2010

Derivative InstrumentNatural Gas . . . . . . . Revenues: Realized gain

on derivatives $1,435,340 $1,172,040 $4,237,540 $2,988,000Revenues: Unrealizedgain on derivatives 2,870,086 2,540,813 1,533,701 5,812,563

Total . . . . . . . . . $4,305,426 $3,712,853 $5,771,241 $8,800,563

NOTE 7 — FAIR VALUE MEASUREMENTS

The Company measures and reports certain financial and non-financial assets and liabilities on a fairvalue basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in anorderly transaction between market participants at the measurement date (exit price). Fair valuemeasurements are classified and disclosed in one of the following categories.

Level 1 Unadjusted quoted prices in active markets that are accessible at the measurement date foridentical, unrestricted assets or liabilities. Active markets are considered to be those in whichtransactions for the assets or liabilities occur in sufficient frequency and volume to providepricing information on an ongoing basis.

Level 2 Quoted prices in markets that are not active, or inputs which are observable, either directly orindirectly, for substantially the full term of the asset or liability. This category includes thosederivative instruments that are valued using observable market data. Substantially all of theseinputs are observable in the marketplace throughout the full term of the derivative instrument,can be derived from observable data or supported by observable levels at which transactionsare executed in the marketplace.

Level 3 Unobservable inputs that are not corroborated by market data. This category is comprised offinancial and non-financial assets and liabilities whose fair value is estimated based oninternally developed models or methodologies using significant inputs that are generally lessreadily observable from objective sources.

Financial and non-financial assets and liabilities are classified based on the lowest level of input that issignificant to the fair value measurement. The assessment of the significance of a particular input to the fairvalue measurement requires judgment, which may affect the valuation of the fair value of assets andliabilities and their placement within the fair value hierarchy levels.

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September 30, 2011


The following tables summarize the valuation of the Company’s financial assets and liabilities thatwere accounted for at fair value on a recurring basis in accordance with the classifications provided aboveas of September 30, 2011 and December 31, 2010.


September 30, 2011 using


Assets (Liabilities)Certificates of deposit . . . . . . . . . . . . . . . . . $– $2,085,313 $– $2,085,313Derivative instruments . . . . . . . . . . . . . . . . – 5,678,112 – 5,678,112

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . $– $7,763,425 $– $7,763,425




Assets (Liabilities)Certificates of deposit . . . . . . . . . . . . . . . . . $– $2,349,313 $– $2,349,313Derivative instruments . . . . . . . . . . . . . . . . – 4,144,411 – 4,144,411

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . $– $6,493,724 $– $6,493,724

Additional disclosures related to derivative financial instruments are provided in Note 6. For purposesof fair value measurement, the Company determined that certificates of deposit and derivative financialinstruments (e.g., natural gas derivatives) should be classified at Level 2.

The Company accounts for additions to asset retirement obligations and lease and well equipmentinventory at fair value on a non-recurring basis. The following tables summarize the valuation of theCompany’s assets and liabilities that were accounted for at fair value on a non-recurring basis for theperiods ended September 30, 2011 and December 31, 2010.

DescriptionFair Value Measurements for the period ended

September 30, 2011 using


Assets (Liabilities)Asset retirement obligations . . . . . . . . . . . . . . $– $– $(535,251) $(535,251)

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . $– $– $(535,251) $(535,251)

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September 30, 2011


DescriptionFair Value Measurements for the period ended




Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . $– $– $(405,345) $(405,345)

For purposes of fair value measurement, the Company determined that the additions to asset retirementobligations should be classified at Level 3. The Company recorded additions to asset retirement obligationsof $535,251 for the nine months ended September 30, 2011 and $847,845 for the year ended December 31,2010, respectively.

For purposes of fair value measurement, the Company determined that lease and well equipmentinventory should be classified at Level 3. The Company recorded an impairment to some of its equipmentheld in inventory, consisting primarily of drilling rig parts, of $50,000 in 2010. The Company periodicallyobtains estimates of the market value of its drilling rig parts held in inventory from an independent third-party seller of similar equipment and uses these estimates as a basis for its measurement of the fair value ofits drilling rig parts.

NOTE 8 — COMMITMENTS AND CONTINGENCIES

Office Lease

The Company’s corporate headquarters are located in 28,743 square feet of office space at One LincolnCentre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas. In April 2011, the Company agreed to a restatedthird amendment to its office lease agreement, in which the office space was increased from 20,849 sqyarefeet to 28,743 square feet and the term of the lease was extended from July 1, 2011 to June 30, 2022. Theeffective base rate over the term of the new lease is $19.75 per square foot per year. The base rate escalatesseveral times during the course of the lease, specifically in July 2015, July 2017, July 2019 and July 2020.

Other Capital Commitments

At September 30, 2011, the Company had entered into two drilling rig contracts to explore and developits Eagle Ford acreage in south Texas. The first rig began drilling on the Company’s acreage in September2011 and the Company anticipates that the second rig will begin drilling operations on its acreage in southTexas in November 2011. Both contracts are for a term of six months. Should the Company elect toterminate both contracts and if the drilling contractor were unable to secure work for both rigs or if thedrilling contractor were unable to secure work for both rigs at the same daily rates being charged to theCompany prior to the end of their respective terms, the Company would incur termination obligations foreither or both rigs. The Company’s maximum outstanding aggregate capital commitment on these contractswas approximately $5.1 million at September 30, 2011.

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September 30, 2011


At September 30, 2011, the Company had outstanding capital commitments to participate in thedrilling and completion of various non-operated wells in the Haynesville shale in north Louisiana. TheCompany has working interests ranging from 0.03% to 4.4% in these wells, and most of these wells arealready in progress. The Company’s estimated minimum outstanding aggregate capital commitments atSeptember 30, 2011 for its participation in these non-operated Haynesville wells are approximately $1.7million.

At September 30, 2011, the Company had outstanding capital commitments with a geophysicalcontractor for two 3D seismic acquisition projects on a portion of its Eagle Ford acreage in south Texas andwith a division of Core Laboratories, LP for core analysis services. At September 30, 2011, the outstandingaggregate capital commitments for these projects were approximately $310,000.

In June 2011, the Company awarded bonuses to certain of its current employees, but not including anyof its executive officers, in the aggregate amount of $1,240,000. These bonuses will be payable in a lumpsum to each of these employees in June 2014, provided each continues to remain an employee in goodstanding with the Company at that time.

Loan Program

As of September 30, 2011, the Company has guaranteed the loans of eight employees (including theExecutive Vice President, Chief Financial Officer and Chief Operating Officer, the Executive VicePresident — Operations and the Vice President — Reservoir Engineering) with a financial institutionpursuant to its Employee Option Exercise Loan Program (“Loan Program”) in the aggregate amount of$1,326,000. The Company considers the fair value of this aggregate guaranty to be minimal and hasrecorded no liability provision associated with this guaranty on its consolidated balance sheets in anyreporting period presented. The Company’s Board of Directors terminated the Loan Program in April 2011,and the Company is no longer authorized to provide financial guaranties for additional loans. No new loanswere guaranteed in 2011 prior to the termination of the Loan Program by the Board of Directors. Nodirector nor the Company’s Chairman and Chief Executive Officer has ever participated in the LoanProgram.

Legal Proceedings

The Company is a defendant in six lawsuits encountered in the ordinary course of its business, none ofwhich, in the opinion of management, will have a material adverse impact on the Company’s financialposition, results of operations or cash flows. Certain of these matters are covered to an extent by insurance.In other cases, the Company believes it has a meritorious defense.

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September 30, 2011

NOTE 9 — SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at September 30, 2011 andDecember 31, 2010.

September 30,2011

December 31,2010

Accrued evaluated and unproved and unevaluated property costs . . . $12,524,849 $12,119,475Accrued support equipment and facilities costs . . . . . . . . . . . . . . . . . 152,553 40,145Accrued cost to issue equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 185,941 359,175Accrued stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . 1,807,318 1,095,014Accrued lease operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . 971,540 428,481Accrued interest on bank borrowings . . . . . . . . . . . . . . . . . . . . . . . . . 244,915 3,235Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,207,940 613,021

Total accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $19,095,056 $14,658,546

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the nine monthsended September 30, 2011 and 2010.


2011 2010

Asset retirement obligations related to mineral properties . . . . . . . . . . . . . . . . . . $ 437,329 $ 82,056Asset retirement obligations related to support equipment and facilities . . . . . . . 15,170 88,192(Decrease)/increase in liabilities for oil and natural gas properties capital

expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,637,909) 8,461,734Increase in liabilities for support equipment and facilities . . . . . . . . . . . . . . . . . . 112,408 –Issuance of common stock and treasury stock for Board and advisor services . . . 124,500 146,250Decrease in liabilities for accrued cost to issue equity . . . . . . . . . . . . . . . . . . . . . (173,235) –Stock-based compensation expense recognized as liability . . . . . . . . . . . . . . . . . (714,934) –Transfer of costs to support equipment and facilities from oil and natural gas

properties capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128,856 –Transfer of inventory from oil and natural gas properties . . . . . . . . . . . . . . . . . . . (313,412) 308,225Interest paid, net of capitalized interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 201,024 –

NOTE 10 — SUBSEQUENT EVENTS

Subsequent events have been evaluated by the Company through December 30, 2011, the date theinterim unaudited condensed consolidated financial statements were available to be issued.

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September 30, 2011


On August 12, 2011, the Company filed a Form S-1 Registration Statement under the Securities Act of1933 with the SEC to commence the initial public offering of its common stock. The Company’s commonstock will not be sold to the public and the Company will not be a public company until the SEC declaresthe Registration Statement effective and the Company’s underwriters complete the sale of its commonstock. The Company filed Amendment No. 1 to the Form S-1 Registration Statement on November 14,2011. As of December 30, 2011, the Company’s Registration Statement has not been declared effective andis still under review by the SEC.

On November 29 and December 27, 2011, the Company entered into various costless collartransactions to mitigate its exposure to oil price volatility, each with an established price floor and ceiling,as summarized in the table below.


PriceFloor

PriceCeiling

(Bbl/month)

($/Bbl) ($/Bbl)

Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12/01/2011 - 12/31/2012 20,000 90.00 104.20Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . 01/01/2012 - 12/31/2012 10,000 90.00 108.00Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . 01/01/2013 - 12/31/2013 20,000 85.00 102.25

For each calculation period, the specified price for determining the realized gain or loss to theCompany pursuant to any of these oil hedging transactions is the arithmetic average of the settlement pricesfor the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding tothe calculation period’s calendar month. When the settlement price is below the price floor established bythese collars, the Company receives from Comerica Bank, as counterparty, an amount equal to thedifference between the settlement price and the price floor multiplied by the contract oil volume hedged.When the settlement price is above the price ceiling established by these collars, the Company pays toComerica Bank, as counterparty, an amount equal to the difference between the settlement price and theprice ceiling multiplied by the contract oil volume hedged.

On December 30, 2011, the Company amended and restated its Credit Agreement with Comerica Bankas Administrative Agent. Among other things, this amendment increased the size of the credit facility andextended the term to December 2016. MRC Energy Company is the borrower under the new amended andrestated Credit Agreement. Borrowings are secured by mortgages on substantially all of the Company’s oiland natural gas producing properties and by the equity interests of certain of MRC Energy Company’swholly owned subsidiaries. In addition, all obligations under the Credit Agreement are guaranteed byMatador Resources Company, the parent corporation. Key financial covenants under the amended andrestated Credit Agreement remain the same.

The amount of the borrowings under the new amended and restated Credit Agreement is limited to thelesser of $400,000,000 or the borrowing base, which was increased to $125,000,000 on December 30, 2011.The $25,000,000 term loan was refinanced by borrowings under the amended and restated Credit

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September 30, 2011


Agreement. As of December 30, 2011, the Company had $113,000,000 of outstanding borrowings under thenew Credit Agreement and $1,262,934 in letters of credit issued pursuant to the Credit Agreement. Allborrowings under the Credit Agreement bear interest at approximately 5.3% per annum.

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APPENDIX A

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used inthis prospectus.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this prospectus in reference tocrude oil or other liquid hydrocarbons.

Bcf. One billion cubic feet.

Bcfe. One billion cubic feet of natural gas equivalents, determined using the ratio of six Mcf of naturalgas to one Bbl of crude oil, condensate or natural gas liquids.

BOE. Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate ornatural gas liquids, to six Mcf of natural gas.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound ofwater by one degree Fahrenheit.

Completion. The operations required to establish production of oil or natural gas from a wellbore,usually involving perforations, stimulation and/or installation of permanent equipment in the well, or in thecase of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Conventional resources. Natural gas or oil that is produced by a well drilled into a geologic formationin which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore.

Coring. Coring is the act of taking a core. A core is a solid column of rock, usually from two to fourinches in diameter, taken as a sample of an underground formation. It is common practice to take cores fromwells in the process of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cutsa column of rock from the formation being penetrated. The core is then removed and tested for evidence ofoil or natural gas, and its characteristics (porosity, permeability, etc.) are determined.

Developed acreage. The number of acres that are allocated or assignable to productive wells.

Development well. A well drilled into a proved oil or natural gas reservoir to the depth of astratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such thatproceeds from the sale of such production exceed production-related expenses and taxes.

Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified asproved, to find a new reservoir in a field previously found to be productive of oil or natural gas in anotherreservoir or to extend a known reservoir.

Farmin or farmout. An agreement under which the owner of a working interest in an oil or naturalgas lease assigns the working interest or a portion of the working interest to another party who desires todrill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its

A-1

interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. Theinterest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.”

FERC. Federal Energy Regulatory Commission.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to thesame individual geological structural feature and/or stratigraphic condition.

Fracture stimulation technology. The technique of improving a well’s production or injection ratesby pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. Aspart of this technique, sand or other material may also be injected into the formation to prop the channelopen, so that fluids or gases may more easily flow from the formation, through the fracture channel and intothe wellbore. This technique may also be referred to as hydraulic fracturing.

Gross acres or gross wells. The total acres or wells in which a working interest is owned.

Held by production. An oil and natural gas property under lease in which the lease continues to be inforce after the primary term of the lease in accordance with its terms as a result of production from theproperty.

Horizontal drilling or well. A drilling operation in which a portion of the well is drilled horizontallywithin a productive or potentially productive formation. This operation typically yields a horizontal wellthat has the ability to produce higher volumes than a vertical well drilled in the same formation. Ahorizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures fordraining like acreage and limiting surface disruption.

Liquids. Liquids, or natural gas liquids, are marketable liquid products including ethane, propane,butane and pentane resulting from the further processing of liquefiable hydrocarbons separated from rawnatural gas by a gas processing facility.

MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet of natural gas.

Mcfe. One thousand cubic feet of natural gas equivalents, determined using the ratio of six Mcf ofnatural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

MMcf/d. MMcf per day.

MMcfe. One million cubic feet of natural gas equivalents, determined using the ratio of six Mcf ofnatural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMcfe/day. MMcfe per day.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or wells.

Net revenue interest. The interest that defines the percentage of revenue that an owner of a wellreceives from the sale of oil, gas and/or natural gas liquids that are produced from the well.

NYMEX. New York Mercantile Exchange.

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Overriding royalty interest. A fractional interest in the gross production of oil and natural gas under alease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling,development, operating, marketing and other costs incident to the production and sale of oil and natural gasproduced from the lease. It is an interest carved out of the lessee’s working interest, as distinguished fromthe lessor’s reserved royalty interest.

Permeability. A reference to the ability of oil and/or natural gas to flow through a reservoir.

Petrophysical analysis. The interpretation of well log measurements, obtained from a string ofelectronic tools inserted into the borehole, and from core measurements, in which rock samples are retrievedfrom the subsurface, then combining these measurements with other relevant geological and geophysicalinformation to describe the reservoir rock properties.

Play. A set of known or postulated oil and/or natural gas accumulations sharing similar geologic,geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanismand hydrocarbon type.

Possible reserves. Additional reserves that are less certain to be recognized than probable reserves.

Probable reserves. Additional reserves that are less certain to be recognized than proved reserves butwhich, in sum with proved reserves, are as likely as not to be recovered.

Producing well, production well or productive well. A well that is found to be capable of producinghydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceedproduction-related expenses and taxes.

Properties. Natural gas and oil wells, production and related equipment and facilities and natural gas,oil or other mineral fee, leasehold and related interests.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other dataand also preliminary economic analysis using reasonably anticipated prices and costs, is considered to havepotential for the discovery of commercial hydrocarbons.

Proved developed non-producing. Hydrocarbons in a potentially producing horizon penetrated by awellbore, the production of which has been postponed pending installation of surface equipment orgathering facilities, or pending the production of hydrocarbons from another formation penetrated by thewellbore. The hydrocarbons are classified as proved but non-producing reserves.

Proved developed reserves. Proved reserves that can be expected to be recovered through existingwells and facilities and by existing operating methods.

Proved reserves. Reserves of oil and natural gas that have been proved to a high degree of certainty byanalysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological andengineering data.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells onundrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. Completing in the same wellbore to reach a new reservoir after production from theoriginal reservoir has been abandoned.

Repeatability. The potential ability to drill multiple wells within a prospect or trend.

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Reservoir. A porous and permeable underground formation containing a natural accumulation ofproducible oil and/or natural gas that is confined by impermeable rock or water barriers and is individualand separate from other reservoirs.

Royalty interest. An interest in an oil and natural gas lease that gives the owner of the interest theright to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof),but generally does not require the owner to pay any portion of the costs of drilling or operating the wells onthe leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of theleased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by anowner of the leasehold in connection with a transfer to a subsequent owner.

2-D seismic. The method by which a cross-section of the earth’s subsurface is created through theinterpretation of reflecting seismic data collected along a single source profile.

3-D seismic. The method by which a three-dimensional image of the earth’s subsurface is createdthrough the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allowfor a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantlyto field appraisal, exploitation and production.

Trend. A region of oil and/or natural gas production, the geographic limits of which have not beenfully defined, having geological characteristics that have been ascertained through supporting geological,geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formationor series of formations.

Unconventional resource play. A set of known or postulated oil and or gas resources or reserveswarranting further exploration which are extracted from (i) low-permeability sandstone and shaleformations and (ii) coalbed methane. These plays require the application of advanced technology to extractthe oil and natural gas resources.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a pointthat would permit the production of commercial quantities of oil and natural gas, regardless of whether suchacreage contains proved reserves. Undeveloped acreage is usually considered to be all acreage that is notallocated or assignable to productive wells.

Unproved and unevaluated properties. Refers to properties where no drilling or other actions havebeen undertaken that permit such property to be classified as proved.

Vertical well. A hole drilled vertically into the earth from which oil, natural gas or water flows or ispumped.

Visualization. An exploration technique in which the size and shape of subsurface features are mappedand analyzed based upon information derived from well logs, seismic data and other well information.

Volumetric reserve analysis. A technique used to estimate the amount of recoverable oil and naturalgas. It involves calculating the volume of reservoir rock and adjusting that volume for the rock porosity,hydrocarbon saturation, formation volume factor and recovery factor.

Wellbore. The hole made by a well.

Working interest. The operating interest that gives the owner the right to drill, produce and conductoperating activities on the property and receive a share of production.

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13,333,334 Shares

Common Stock

Prospectus

February 1, 2012

RBC CAPITAL MARKETS CITIGROUPJEFFERIES

HOWARD WEIL INCORPORATED STIFEL NICOLAUS WEISEL

SIMMONS & COMPANY INTERNATIONAL STEPHENS INC. COMERICA SECURITIES

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Stifel · PROSPECTUS 13,333,334 Shares Matador Resources Company Common Stock Matador Resources Company is offering 11,666,667 shares of its common stock, and the selling shareholders